Well Productivity AWARENESS WELL PRODUCTIVITY AWARENESS SCHOOL All rights reserved. Without limiting the rights under copyright reserved, no part of this publication may be reproduced, stored in, or introduced into, a retrieval system, or transmitted in any form or by any means (electronic, mechanical, photocopying, recording, or otherwise), without the prior written admission of TRACS International Training Ltd. and BP Exploration. Revision 2: 2001 TABLE OF CONTENTS INTRODUCTION 3 Course Objectives Economic Importance of Well Productivity Introduction to Notes Acknowledgments 4 6 7 7 OVERVIEW OF WELL PRODUCTION 9 Well Type Influence of Geology How Wells Produce Formation Damage/'Skin' Types of Formation Damage Module Summary 11 14 20 25 31 35 DRILLING THE RESERVOIR 37 Drilling Fluids Fractures Drilling Underbalanced Coring Module Summary 39 55 57 60 63 COMPLETIONS 65 History Completion Types Multilateral Wells Geosteering Completion Practices Module Summary STIMULATION Acidisation Microbal Treatments Hydraulic Fracturing Module Summary 66 67 71 76 80 119 121 123 139 141 156 WELL PRODUCTIVITY AWARENESS SCHOOL PRODUCTION RELATED FORMATION DAMAGE Precipitation Fines Migration Phase-Related Permeability Reduction Stress Induced Permeability Change Injection Wells Module Summary WORKOVERS Types Workover Practices Water Shut Off Treatments Coiled Tubing Module Summary SUMMARY Where Do We Go From Here? Communication GLOSSARY 157 159 167 168 170 171 172 173 174 176 188 190 200 201 218 219 207 INTRODUCTION Revision 2: 2001 Introduction 4 Course Objectives 4 Economic Importance of Well Productivity 6 Introduction to Notes 7 Acknowledgments 7 3 WELL PRODUCTIVITY AWARENESS SCHOOL Introduction Course Objectives The objective of the course is to make all participants aware of the following: • • How your job can impact on well productivity Where you can make a difference By enhancing your knowledge of Well Productivity and Formation Damage, the course will make you aware of the consequences of your actions when you are involved in an operation; be it a planning role in the office, or an operating role on the rig. Well Productivity is influenced by your actions throughout the life of a well; ♦ ♦ ♦ ♦ ♦ ♦ Drilling Testing Completion Production Workover Stimulation The planning or operational decisions you make impact the whole life of the well ; not just its immediate future. This course involves both Operator and Contractor/Service Company personnel, because everyone needs to be involved. Contributions from the floor are welcomed, to combine local knowledge and problems with the course contents. There is increasing emphasis for contractors and service companies to provide a ‘product’, ‘an undamaged well’, rather than just a service or a piece of equipment. The responsibility for planning, drilling and operating a successful well is shifting from the Operator to the Contractor/Service company. This success is important to: • • Gain more work for your particular company. To encourage the Operator to develop more marginal fields. The drilling of successful undamaged wells will mean a secure future. PROFITABLE FIELD DEVELOPMENT – MORE WORK – JOBS 4 Revision 2: 2001 INTRODUCTION Potential rates If the formation is damaged, the plateau rate cannot be sustained. Cash flow is diminished Profitability declines Agreed plateau rate With damage No damage Too little, too late Money must be spent to stimulate the well. Therefore lower profitability. Abandonment 0 2 4 6 8 10 12 14 16 Production time (years) ECONOMIC IMPORTANCE OF WELL PRODUCTIVITY Well Productivity Awareness - The Team Mud Cementer Drilling Engr Logger Stimulation Engr Geologist Fluids Engr Rig Hands Others Logging Engr Reservoir Engr Driller Q Company Man Revision 2: 2001 Completions Engr Tool Pusher A Why should formation damage concern you? Because it means less production 5 WELL PRODUCTIVITY AWARENESS SCHOOL Economic Importance of Well Productivity It has always been known that formation damage or well impairment leads to lower production rates and, thereby, a loss of revenue. BP quantified this loss in financial terms (for their operated fields and seven partner-operated fields) in a report written in January 1991. They concluded that: “The potential ‘net present cost’ of formation damage to BPX, assessed over the remaining life of currently producing fields, is estimated to be in the region of $1.5 billion, before the effect of taxation”. The above calculation was arrived at by taking into account: • • Expenditure on remedial/inhibitive treatments Loss of value resulting from deferred production (and therefore deferred cash flow) A key assumption was that ‘formation damage did not result in any LOST production’. The pre-tax figure of $1.5 billion is therefore conservative. Some of this loss is already being avoided with procedures underway, and some of the loss may never be prevented; however there is potential for considerable improvement . THIS IMPROVEMENT IS THE RESPONSIBILITY OF EVERYONE. Every oil company suffers from well impairment. One company in the US Gulf Coast increased its well productivity from 2 to 20 stb/d/psi through concerted efforts to improve well completion techniques and reduce formation damage. This means that an average well would produce at 30,000 bbls/day instead of just 3000 bbls/day. A major oil company estimated that if formation damage had not occurred (or could be removed) in their gravel-packed wells they could be producing an extra million barrels of oil per day worldwide ≅ $20,000,000/day. We believe that enhanced awareness of the problem, and the cost savings and increased production emanating from that knowledge, will be the ultimate dividend from Well Productivity Awareness training. 6 Revision 2: 2001 INTRODUCTION Introduction to Notes These notes roughly follow the course presentation and provide a reference document. Not every viewgraph shown during the course is included in this book, nor is every illustration in this book used as a viewgraph. All the exercises done during the course will be handed out at the time. There is a Glossary after the Summary Section, which attempts to cover all of the terms with which you may be unfamiliar. Acknowledgements This course was compiled using information gathered from BP’s 'Basics of Damage and Stimulation' (PPTO42) school and Mr. Peter Greaves prepared the manual with the assistance of BP Research Centre (UTG). The project has involved many different disciplines, and has received input from John Mason, Phil Smith, Bill McLellan, Sandy Petrie, Ian Pitkethly and James Cobbett. Several service companies have been generous contributors, most noticeably Baker-Hughes INTEQ. The Schlumberger organisations have provided graphics and presentation materials from their 'Oilfield Review', and from their own training centres. Halliburton and Sperry Sun have also contributed materials for the school. TRACS International Training Ltd. February 2001 Revision 2: 2001 7 WELL PRODUCTIVITY AWARENESS SCHOOL 8 Revision 1: January 1995 O V E RVIEW OF WELL PRODUCTION Overview of Well Prroduction 11 Well Type Exploration Appraisal Development Influence of Geology The Reservoir Porosity and Permeability Rock Type Rock Analysis Reservoir Geometry and Permeability Distribution Revision 2: 2001 11 11 13 13 14 14 14 17 20 How Wells Produce 20 Formation Damage/'Skin' 25 Definitions a. Linear Flow vs. Radial Flow b. Formation Damage c. Skin d. Flow Efficiency e. Productivity Index f. What is optimum Skin Factor? 25 25 25 27 29 29 31 Types of Formation Damage 31 MODULE SUMMARY 35 9 WELL PRODUCTIVITY AWARENESS SCHOOL Radio location antenna Floating firing line Radar reflector tail marker Shot 24 * 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Fathometer Geophone cable MARINE REFLECTION SHOOTING Dry Hole Oil Well Seismic reflection time Top Balder Base Tertiary Base Chalk Base Cretaceous Base Reservoir Top Zechstein 0 1 km Migrated seismic section through an oil field 2000 Shales Chalk 3000 Shales Sand Shales + + 4000 + + + + + + + + + + 5000 + + + + + + Caprock (seal) Oil Source rock Water Reservoir + + + + + + + + + + + + + + + + + + + + +Salt + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + 0 1 km 6000 Cross section through the oil field, drawn along the line of the seismic section (No vertical exaggeration) 10 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Overview of Well Production At the end of this module you should be aware of: * * * * * The main reservoir characteristics that affect well productivity How oil flows from the reservoir into the well The importance of the near wellbore region What formation damage is How to compare the productivity of different wells Well Type Exploration Prior to any drilling, the geophysicists of the Exploration Department have shot seismic and have interpreted the results. The interpretation of the seismic will define a structure to be drilled. The geologists will ascertain whether or not there is likely to be a reservoir rock and a source rock. An exploration well is the first one to be drilled on a prospect. The main aims of the well are to establish whether hydrocarbons are present. The geological data taken from cuttings, cores and electric logs are the prime objectives of the well. If the well is successful in finding hydrocarbons it may be production tested. Any formation damage will become evident during the testing of the well (although it may also have caused some log interpretation problems earlier); in an extreme case severe formation damage could mean a valuable field is completely missed. In an exploration well, the aim is to obtain the above information at the lowest cost. Good quality data are required; this takes priority in well design and execution. Most exploration wells are currently plugged and abandoned (although there is an increasing trend both on land and offshore to keep successful exploration wells, and therefore formation damage should be minimised as much as is practicably possible). EXPLORATION WELL Drilled for geological information, often plugged and abandoned but increasingly kept for production. Formation Damage: Not critical if well is to be P&A'd. However poor hole condition and deep fluid invasion will hamper log interpretation. Skin values recorded during well testing require interpretation. Cores should be cut in the reservoir. APPRAISAL WELL to test the western extension of the field. Cores are cut in the reservoir. In the design stage, attempts should be made to reduce damage caused in the Exploration Well (high skins). WATER INJECTION WELL Water may be injected into the aquifer below the hydrocarbons to maintain reservoir pressure. Formation damage is often by-passed by small induced fractures. Subsea Completion P Exploration Well Appraisal Well Subsea Completion TYPES OF WELL Revision 2: 2001 Development Well Injection Well DEVELOPMENT WELL It is critical that the design and execution of the well minimises damage. The well completion must optimise/maximise well productivity. Platform P APPRAISAL WELL to test downdip extension of oil column. 11 WELL PRODUCTIVITY AWARENESS SCHOOL A A Structure Structure • • • • • A A Cap Cap rock rock • Impermeable • Widespread Anticline Dome Fault trap Sedimentary trap Salt diapir A A Reservoir Reservoir • Porosity • Permeability • Hydrocarbon Saturation Oil A Kitchen? A Structure (Source Rock) Water • Generation of hydrocarbons countless millions of years ago OWC WHAT MAKES AN OIL/GAS FIELD? a) Stage 1 : Diagrammatic section across strata before folding begins Sea level Sea Sandstones etc Limestones Salts, marls, anhydrites etc Anhydrite (Cap rock) Limestone reservoir Shale formation All strata flat, oil in limestone beginning to separate out from water and take its place in the more porous bands. Note also the general tendency for the oil to migrate upwards via joints. It will be held up finally by the completely impervious b) Stage 2 : Diagrammatic section across gently folded strata Early stage in folding Gas seepage Conglomerates Sandstones etc Limestones Salt, marls, anhydrites etc Anhydrite (Cap rock) Limestone reservoir Shale formation c) Stage 3 : Diagrammatic section across more intensely folded strata Conglomerates Anticline Spill point Sandstones etc Limestones Salt, marls, anhydrites etc Anhydrite (Cap rock) Limestone reservoir Shale formation Syncline Showing disharmonic folding of upper beds due to plasticity and flow of salt, marl and anhydrite formation. Oil Gas Water HOW AN OILFIELD DEVELOPS IN THE COURSE OF AN EARTH FOLDING MOVEMENT 12 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Appraisal An appraisal well is drilled as the intermediate stage between exploration and production, to determine the size of a field and its reservoir properties and how much the wells will produce. Since the geology of the area is now better known, the drilling and completion of the well can be better designed to achieve a minimally damaged well. This should further enhance the quality of the data, to allow the geologists and reservoir engineers to have greater confidence in their production predictions for the life of the field. Poor quality data could lead to incorrect decisions being made about important factors such as the number of wells, number of platforms and plateau production rates. If a damaged appraisal well flows at low rates then the Operator may decide not to develop the field, because of a lack of confidence in the reservoir, and whether or not it can be drilled without damage. Remember: MORE DEVELOPMENT – MORE WORK – MORE JOBS. Development The development plan is now written and the number of wells (producers/injectors) has been defined. The production from (or injection into) these wells has been predicted using a ‘skin factor’ to allow for formation damage and completion efficiency. The economic viability of the field is based upon these predictions. If the development wells are damaged more than predicted, the field stands a chance of being unprofitable. If the industry – you the oil company engineers, contractors and service companies – cannot drill, complete and operate these wells as per the specification, the field could be uneconomic. It will be abandoned prematurely – and the next field of its kind will not be developed. Minimising formation damage is most critical in field development wells, but also very important in appraisal wells. Formation damage must also be minimised in exploration wells, but only after considering the priority need for goal data. Principal Ways By Which Formation Damage Costs Money Revision 2: 2001 Type of Well Type of Cost Exploration Missed oilfields Poor quality data Appraisal Poor quality data More appraisal wells Remedial treatments Poor facilities design Development/ Production More production wells Lower plateau rate Remedial treatments Lower reserves Lower water injectivity Costly facility modification Premature abandonment 13 WELL PRODUCTIVITY AWARENESS SCHOOL Influence of Geology The Reservoir Porosity and Permeability Except in very rare exceptions (fractured granite), hydrocarbons are found in sedimentary rocks . Sedimentary rocks are laid down as ‘pieces’ (grains) or ‘clastics’ with time, usually in an aqueous (water-borne) environment. The exception to the aqueous environment is the aeolian, or wind transported, environment. Modern day examples of sedimentary environments are beaches, sand bars, lagoons, swamps, estuaries, deltas, rivers and deserts. The two most important factors that make a good reservoir are porosity and permeability: the porosity is the percentage of void space in the rock where fluids are stored, and the permeability is a measure of the interconnection of the voids. Porosity can be measured in the well using electric logs; permeability is far more difficult (a formation tester can measure permeability). Both properties can be measured in the laboratory on good core samples. The pore space (p o ro s i t y ) in a hydrocarbon reservoir is not filled entirely with oil or gas; there will be some water present. This is known as ‘Sw’, the ‘Water Saturation’. The Sw is the percentage pore space containing water. It is the porosity that effects the volume of oil/gas in place. Porosity is the void space in the rock, expressed as a percentage of the rock volume Permeability is a measure of how easy it is for fluids to flow through the pore system It is the permeability that affects well productivity Pore throats are narrow restrictions between grains which connect larger voids POROSITY AND PERMEABILITY The permeability , ‘k’, is expressed in milliDarcies, and measures the ability of fluid to pass through the rock. The connections between the voids of the rock are known as pore throats – these MUST be kept open. Rock Type Hydrocarbons are usually found in sandstone and carbonate reservoirs; although there are a few rare exceptions such as fractured granite, volcanic tuff and oil shales. Within the simple definition of sandstone and carbonates there are many variations: 14 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Sandstone Carbonate • • • • • • • • • • • • • • Grain Size Grain shapes Degree of Cementation Cleanliness Clay Content Heterogeneity (rock variability) Mineral Type (Calcite/Dolomite) Particle Size Degree of Cementation Type of Cementation Diagenesis (changes in the rock) Induration (fusing of rock grains) Heterogeneity Clay Content Sandstones are granular sedimentary rocks with grain sizes between 0.0625 and 2mm (‘sand’ is a size classification). The pore space, where hydrocarbons can be held, is between the grains. The grains are mainly composed of quartz, but feldspar, chert, mica and other rock fragments are also common. Clay minerals are often present. Degree of grain cementation Grain size and sorting Grain shape Clay content - type - distribution SANDSTONES – WHAT YOU NEED TO KNOW The grains in a sandstone may be cemented together during burial (diagenetic modification). Cements include quartz, carbonates (e.g. calcites and dolomite) and clays. The pore system may be lined with, or filled by, clay minerals such as kaolinite, smectite, chlorite, or illite. Conglomerates are similar to sandstones but have much bigger grains (pebble grade = 4-64mm). The space between the pebbles may be partially or completely filled by sand grains. These rocks can also form reservoirs. Mudstones are sedimentary rocks which consist of particles finer than sand grade (less than 0.0625mm) and include both silt and clay grade material. Most of the particles in mudstones are clay minerals. Mudstones are commonly referred to as shales . Though mudstones have porosity, they have negligible permeability (usually less than 1 mD) so they normally form sealing barriers both within and at the boundaries of the reservoir. Revision 2: 2001 15 WELL PRODUCTIVITY AWARENESS SCHOOL Carbonates are composed of carbonate minerals (e.g. calcite and dolomite). The carbonate is commonly in the form of shells or other skeletal material. Porosity can be inter-particle (in between the particles, as in sandstones) or intra-particle due to the dissolution of grains (secondary porosity). Compared to sandstones, carbonate rock pores are often poorly connected and matrix permeability is low, but fractures are more common. There are various types of carbonate: Grain replacement (dolomitization) Grain dissolution Grains - size - type Degree of cementation CARBONATES - WHAT YOU NEED TO KNOW • • • • Limestone Dolomite Chalk Marl Made of calcite (CaCO3) Made of dolomite (CaMg(CO3)2) Soft, fine grained limestone made of calcite Rock made of calcite and clay minerals Clay Minerals are fine grained lattices of layered silicates. They may occur in sandstones either in patches (e.g. where they have replaced less stable grains) or as a pore lining (e.g. the hairy illite seen in the Magnus and Southern N. Sea fields). The distribution and type of clays is just as important as the amount of clays when considering whether or not a rock is sensitive to damage. Clays are an important consideration as to whether a formation is 'sensitive'. The main types of clay mineral are: When the clay is in an isolated clast it is less likely to cause a formation damage problem even if it is a swelling clay like smectite DISTRIBUTION OF CLAYS Use rock analysis to investigate potential formation damage problems. 16 There may be less clay in this sample, but if it is a smectite (swelling) it will block the pores if it is allowed to swell. Alternatively if it is a ‘hairy’ illite clay it could entrap fines and similarly cause a blockage Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION • • • • Kaolinite – plate booklets prone to migrate Illite – fibres prone to catch moving fines Chlorite – random platelets (often iron rich/beware during acidisation) Smectite – prone to swell and block pore throats ILLITE CHLORITE KAOLINITE Montmorillonite – so often the guilty party in hole problems – falls within the smectite group of clays. Bentonite, used for drilling, is a smectite. Rock Analysis The microscopic details of the rocks are not known at the exploration stage of drilling. However, if a reservoir is encountered, a good core (including preserved core) should be obtained for close examination. The geologists are naturally keen to see what rocks they have, and to age-date them; the reservoir engineer may subject the core to ‘special core analysis’ (using preserved core) to obtain all the parameters necessary for his reserves calculations (porosity, permeability, relative permeability, capillary pressure curves, etc.); and the drilling engineers, completion engineers, mud engineers – indeed all the petroleum and drilling engineers – should be interested in the core to investigate potential formation damage, to improve the design of any subsequent wells. To this end the following analyses may be carried out: • • Revision 2: 2001 Thin Section – – – Microscopy pore spaces visible using a blue resin minerals identified with polarised light microscope gives 2D picture of pore structure, location of cements and clays – different clay minerals not distinguished Scanning Electron Microscopy (SEM) – 3D view of rock surface – identifies type and distribution of clay minerals 17 WELL PRODUCTIVITY AWARENESS SCHOOL Fault trap Stratigraphic Normal fault Reverse fault B Impermeable Compression Tension 1 A Impermeable 1 3 2 x 3 2 Plan x1 Porous and permeable 4 x1 x1 Oil Water Water Section x1 x Oil Two kinds of faults are shown, a normal fault resulting from tension on the left and a reverse or compression fault on the right. In both cases the effect is to seal off a permeable bed (2) by bringing it opposite an impermeable one (1) across the fault so allowing an accumulation of oil (3) to be trapped. The distance indicated by (4) shows the horizontal displacement of beds caused by fault movement. Permeable Plan x 4 x Section This illustration shows the plan and section of two oil traps caused by changes in rock permeability. On the left a permeable zone is entirely surrounded by impermeable rock, such conditions are found where fossil reefs occur. On the right a lithological change occurs along an arc - possibly parallel to a fossil shoreline. Salt dome Compression Salt plug Before compaction This shows how beds are domed up over a piercement salt plug which has torn its way through the lower beds. Oil or gas traps can occur wherever a permeable bed is truncated by the salt plug or in the anticlines over the crest of the plug. After compaction This illustration shows the changes in beds deposited on an irregular sea floor after compaction caused by additional overburdening. It will be noted that the thinning is greatest over the buried crests. Reef (Carbonate) Unconformity Inferred current direction One series of rocks has been deposited, tilted and eroded off. Subsequently a second series has been laid down over the eroded surface and the whole subjected to further tilting. Traps occur at the unconformity surface when a permeable bed is sealed by the lowest impermeable bed of the upper series. This illustration shows a reef with one side washed clean by current action whilst on the lee side beds of coral detritus are accumulating. Such conditions are found where reefs contain a lagoon. Traps can occur in the reef itself or in the beds of detritus. VARIOUS KINDS OF OIL TRAPS SAND BODY DISTRIBUTION Less Productive Well Productive Well BARRIERS TO FLOW WILL INFLUENCE THE MOVEMENT OF OIL AND WATER Shale barrier of field-wide extent Well missed channel sand. No flow when tested Field will drain as two large separate compartments Well hit coarse-grained channel sand Test rate: 1500 stb/day FRACTURES need to know the direction of OPEN fractures (not just all fractures) ALL FRACTURES OPEN FRACTURES ONLY N OIL N OWC Shale barriers WATER LESS PRODUCTIVE WELL Horizontal section drilled NW-SE to cut all fractures Test rate: only 295 stb/day “upper compartment” “lower compartment” PRODUCTIVE WELL Horizontal section drilled NE-SW to cut open fractures Test rate: 7300 stb/day Fractures 18 Wellbore Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION • • X-ray Diffraction (XRD) – identifies minerals present – special clay fraction analysis may be requested Mercury Porosimetry – determines distribution of pore throat sizes – mercury is injected at stepwise increasing pressures – large pores fill first, smaller pores fill at successively higher pressures – volumes injected at different pressures give an indication of pore size distribution – useful for establishing whether solids will penetrate a rock or form a filter cake It is wise to check how the samples have been prepared; for instance gold is sometimes used to prepare SEM specimens – to bleed away excessive electron beam charging. Gold tends to collapse the clays giving a false impression of porosity and permeability. Where clay swelling is thought to be a potential cause of formation damage, not only is the amount and type of clay important, but so is its location. For example, a sample may contain 5% swelling smectite clay, but if that clay is located in one isolated mudstone clast then the sensitivity to damage is small. Alternatively, if 3% smectite lines the whole pore system, then damage potential is high. Fines migration damage sensitivity is not so easy to determine by looking at rock samples. Firstly, potentially mobile fines are not restricted to clay minerals, and can include any small minerals, for example microcrystalline quartz, feldspar crystals and fragments of partly degraded grains (e.g. microporous chert). Clays are, however, very important (and potentially mobile) fines, so they figure strongly in any assessment of damage sensitivity. To assess fines sensitivity, the questions to ask are: • • Are there any fines in the rock? How susceptible are they to mobilisation? If fines are in discreet patches, such as where kaolinite aggregates have replaced feldspar grains, or partially degraded chert grains, then the potential for fines problems will be less than if the fines line or partially fill the major pores. If the fines have been enclosed by a later cement, then they are unlikely to be mobilised unless that cement is disturbed. It pays to view a reasonable number of samples/specimens of the rock to get a representative picture of the formation; one or two slides/SEM/XRD are not enough. The above describes what can be done to actually look at and define the rock. There are also tests than can be done on core plugs, such as ‘return permeability’ tests and these are described later in this book. Revision 2: 2001 19 WELL PRODUCTIVITY AWARENESS SCHOOL Reservoir Geometry and Permeability Distribution Geological characteristics can influence well performance in two main ways: Permeability distribution – flow units, layering, tight (cemented) zones, high permeability streaks, fractures Boundaries – faults, slumps, unconformities It is important to have a good understanding of these characteristics. We cannot change the geology but we can adapt our field development plans to make the best use of what we’ve got. A thorough knowledge of all these features can help us to adopt drilling and completion procedures to minimise formation damage. Variations in permeability and reservoir geometry within the drainage radius of a well can have a major effect on well performance. An example would be a sealing fault very close to the well which would cause a slope change (part of the test interpretation procedure) on a well test pressure plot which might be wrongly interpreted as damage. The location of faults and/or the characterisation of fractures is important to well test interpretation. Permeability Layering influences well performance. If layering is defined by permeability barriers, then some layers could remain undrained if the completion does not account for the barriers to flow. If the layering is defined by variations in permeability, rather than barriers, then the contrast between horizontal and vertical permeability will influence well performance. The determination of the Kv/Kh ratio (permeability anisotropy: vertical/horizontal) from routine core analysis data is an important part of geological characterisation. However Kv/Kh changes depending on what scale you are considering: over reservoir thickness the Kv/Kh is usually much less than Kv/Kh in core plugs. How Wells Produce A well produces oil or gas when the pressure of the oil or gas in the reservoir pushes the fluids to surface. If the pressure of the reservoir is insufficient to get the fluids to surface, then the well has to be pumped or gas-lifted (artificial lift). Whilst drilling a well the hydrostatic pressure of the drilling fluid is used to suppress the reservoir pressure that will later bring the hydrocarbons to surface. Once a reservoir is on production, the reservoir pressure may decline as the energy in the system is gradually exhausted by the production of fluids. If the reservoir has an ‘active’ drive system, such as a massive charged water reservoir below the oil, then the pressure will not decline as fast and the production will remain healthy – all other factors remaining equal. It is however, often necessary to maintain reservoir pressure by injecting water into the reservoir below the oil. When a well is producing there are pressure losses in the system. The ones that concern well productivity are: a) b) 20 in the formation up the tubing Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Pwh, Wellhead flowing pressure Pressure losses in the tubing Pw, Bottomhole flowing pressure Pr, Fluid pressure at reservoir boundary Pressure losses in the reservoir PRESSURE DROPS CONTROLLING WELL PERFORMANCE The pressure drops are usually plotted against flowrate to give: a) b) the inflow performance relationship or IPR the tubing performance curve or lift curve The intersection of these two curves gives the flowrate at which the well will produce. Any damage to the well will change the IPR. Factors such as tubing size and wellhead pressure will change the lift curve. The drawdown on a well is the pressure difference between the wellbore and the reservoir, that causes the oil or gas to flow into the well from the reservoir. Tubing Performance Curves: Calculated by computer or taken from tables, to predict the pressure loss up the tubing. Depends upon rate, type of fluid (oil vs gas), gas-oil-ratio, water content etc. for different tubing sizes. Bottom hole flowing pressure If bottom hole flowing pressure is the same as the reservoir pressure the well will not flow 31/2" Natural flowrate: in this particular case the well will flow naturally at this rate with this tubing in the hole Pw Pr 41/2" 51/2" The lift curve = 'required pressure' (For a particular sized tubing) drawdown Pump pressure (If a higher rate is required) As the bottom hole pressure is reduced the well begins to flow -pushed by the reservoir pressure. The greater the drawdown the greater the flow The IPR = 'Available pressure' Flowrate Barrels of Oil per Day INFLOW PERFORMANCE RELATIONSHIP (IPR) AND TUBING PERFORMANCE CURVES Note: Although the radial flow equation is linear, the IPR line is not a straight line. This is because the IPR equation makes some assumptions. For instance in a real oil well the increasing drawdown (lower bottom hole pressure) may lead to more gas being evolved in the near wellbore region, causing higher gas saturations and more resistance to oil flow. Revision 2: 2001 21 WELL PRODUCTIVITY AWARENESS SCHOOL How Wells Produce - Water Drive a) b) Cap rock Oil Water At an early stage of production. At a later stage where the rising water has reached the foot of the well with the result that it has gone to water. The height of the water column in the well is a measure of the pressure of the water zone. How Wells Produce - Solution Gas Drive a) b) Gas zone where pressure has fallen below saturation pressure due to production and gas is coming out of solution Ingress of water from aquifer restricted or non-existent With the formation and expansion of the gas cap a liner must be put in to extend casing below the gas/oil level as the well would otherwise produce gas only Cap rock Oil Water Early stage in solution gas drive production. 22 A later stage where a gas cap has formed due to gas coming out of solution in the reservoir when the pressure falls below saturation pressure. Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Diagrams showing the arrangement of gas, oil and water in typical dome-shaped structures a) Gas cap Gas/oil contact Oil/water contact Cap rock Aquifer Cross section through an oil reservoir Oil Oil/water contact b) 4 Water Gas/oil contact 2 Gas 8 6 1 5 7 3 Wells which struck oil - No.1 (discovery well) 2, 5, 7 and 8 Well No.3 struck oil and then passed into water Underground contours (usually marked in feet below sea level) Contour map defining size and shape of reservoir as indicated by the drilling of the discovery well and 7 appraisal wells Revision 2: 2001 23 WELL PRODUCTIVITY AWARENESS SCHOOL ∆p Flow Core Length L Pump Flowrate Q Core Area A Q= Ak ∆p µL LINEAR FLOW radius of damaged region radius of the well rd rw undamaged reservoir kd = permeability of damaged region RADIAL FLOW Imagine the drainage area of this well. Oil that is one thousand feet away has plenty of room to travel through the reservoir to the wellbore. BUT as it gets closer and closer there is less and less room. The near wellbore region therefore becomes crucial: damage this and you severely impair the wells productivity. NEAR WELLBORE DAMAGE 24 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION The pressure losses in the formation are dealt with more fully in Section entitled ‘Formation Damage/Skin’. The production of oil will be impaired or reduced by the production of water . Water production may be unavoidable due to the nature of the reservoir; however efforts should always be made to complete a well to minimise water production. In an oil well, efforts are usually made to minimise the production of gas, which can also impact upon the well productivity. Formation Damage/‘Skin’ Definitions a) Linear Flow vs Radial Flow Imagine the passage of a fluid (gas or liquid) through a porous medium, say a cylindrically shaped piece of rock. The fluid needs pressure to force it from one end of the cylinder to the other and it needs an interconnection of holes (the permeability) through the rock to allow the passage of the fluid. The rate at which the fluid passes through the rock will depend upon the: • • • • • cross-sectional area, A permeability, k pressure drop across the block, ∆p the length of the block, L the viscosity, µ (the thicker it is the slower it will pass through) This is linear flow . Henri Darcy studied the subject and gave his name to the measurement of permeability, the Darcy. However, when fluid is flowing from a distance (the reservoir limit) to the wellbore it is described as radial flow . The diagram opposite illustrates radial flow into a well. The more detailed diagram on the following page illustrates the calculation of radial flow. The equation that makes up the calculation is described in the following section. It can be seen that the pressure drop in the reservoir (psi/ft) increases significantly as you move closer to the wellbore – and this is for an undamaged well. If there is 'damage' in the near wellbore region the pressure drop will be even greater, thus reducing production. b) Formation Damage Formation damage may be defined as: “A reduction of permeability around a wellbore, which is the consequence of drilling, completion, injection, attempted stimulation, or production of that well” Revision 2: 2001 25 WELL PRODUCTIVITY AWARENESS SCHOOL AN EXAMPLE OF RADIAL FLOW UNDAMAGED WELL Darcy's Law Undamaged Well 100mD Permeability Zero Skin Q= 0.00708kh (Pr-Pw) Bµ (Logn [re/rw]+S) 20,000 stb/day 8.5" hole Reservoir Thickness = 50ft Distance from well (feet) 1 ft 100 ft 1000 ft Flow velocity (ft/day) 1600 16 1.6 Pressure drop (psi/ft) 900 5.6 0.6 100 1000 1 10 Reservoir Pressure pressure 7000psia Radius Radius (ft) 7000 1300psi 6000 5000 Pressure 4000 (psia) Bottomhole flowing pressure 2500psia 3000 2000 1000 0 1300psi 1300psi 600psi pressure drop in 8 inches Notice the huge pressure drop in the last eight inches around the wellbore. You can imagine how badly the well productivity would be affected if this pressure drop was even greater due to formation damage As an illustration; if this well were damaged and had a skin of +2, this 600psi would become 1200psi. Thus to achieve 20,000 stb/d, the well would have to be drawn down to a further 1120 psi. The bottom hole flowing pressure would have to be 1380psi. This may not be possible in reality. Also, this may bring the bottom hole pressure below the bubble point, at which point gas comes out of the oil and further hinders production and lowers productivity. More realistically you would continue to produce at the same drawdown (4500 psi) but you would only produce 16000 bopd. 26 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION The previous section spoke of the Inflow Performance Relationship. To understand the term skin we need to define the IPR and see where the relationship to skin lies. The inflow performance for an oil well is derived from analysing radial flow: Q= 0.00708 kh(Pr - Pw) Bµ(Logn{re/rw} + S ) where: Q k h Pr Pw B = = = = = = µ re rw S = = = = flowrate in stock tank barrels/day (stb/d) permeability in mD (millDarcy, 1000’th of a Darcy) vertical formation thickness in ft reservoir pressure at boundary in psia bottom hole flowing pressure in psia formation volume factor in reservoir barrels/stock tank barrel (rb/stb) viscosity in centipoise (cP) drainage radius of reservoir in feet wellbore radius in feet Skin – a dimensionless number Shaded items are fixed values for a particular reservoir The constant 0.00708 is a conversion for the oilfield units used here. This equation is known as the steady state radial flow equation for oil, where the reservoir pressure is held constant, as would be the case in a waterflood. This equation will give us the flowrate for an ideal vertical well, fully completed (open-hole) with no formation damage (if S=0). There are similar equations for pseudo-steady state flow and for gas wells. The 'skin' of a well can only be calculated from analysis of a well test. It cannot be physically measured. Good data on how skin changes over time may lead to a timely discovery of a developing formation damage problem. c) Skin The skin was ‘discovered’ in the early days of well testing. An extra pressure drop was observed close to the well in addition to that expected from ideal radial flow. Since this pressure drop will vary with the flowrate and the viscosity of the fluids, it is useful to define this in terms of a dimensionless skin . S= 0.00708 kh ∆P skin QµB A positive skin means that the pressure drop in the formation close to the wellbore is greater (and the productivity therefore lower) than an ‘undamaged’ well having zero skin. A negative skin factor means that productivity is higher than the zero skin case. Revision 2: 2001 27 WELL PRODUCTIVITY AWARENESS SCHOOL The skin can be a mechanical skin due to formation damage, or a skin due to the completion geometry (including the effects of 'partial completion' well orientation, perforations etc. See the Completions Section). There can also be a ‘non-Darcy’ skin, for example skin in a high rate gas well due to turbulence causing an extra (frictional) pressure drop. For example: Skin 0 +2 +4 +8 +24 +100 +1000 -1 -3 -4 -6 Rate (bpd) 10,000 8000 6667 5,000 2,500 740 80 11,400 16,000 20,000 40,000 '(ideal)' no damage increasing damage increasing stimulation Note that skin can be positive to infinity, but negative to about -6, possibly -7. The theoretical minimum is -8. The diagram below illustrates ‘skin’ around a wellbore. Because the reservoir pressure is required to ‘push’ the hydrocarbons through this extra barrier, less energy is available to get the fluid to surface, so for a given drawdown on the well, less hydrocarbons will make it to surface. SKIN: Formation Damage is commonly around eighteen inches from the well - although it is dangerous to generalise. It can go several feet into the reservoir. rs rw undamaged rw = wellbore radius rs = radius of damage p = pressure P wf = wellbore flowing pressure Actual pressure Pressure when no skin present ∆pskin = Additional pressure drop due to skin effect damaged Skin region P wf distance from centre of well PRESSURE DROP DUE TO SKIN 28 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION In real life, an additional pressure drop around the wellbore may not simply be overcome by applying more drawdown, since reservoir or regulatory constraints may prevent this or indeed the tubing lift curve may make this untenable. d) Flow Efficiency Although the skin is a useful mathematical concept, it does not give a good feel for the effect of well damage on flowrates. The flow efficiency is a more useful quantity: Flow Efficiency = Flowrate with actual skin Flowrate with zero skin = Logn(r e/rw) Logn(r e/rw) + S = 8 (to a good approximation) 8+S The flowrates, corresponding to actual and zero skins, must be measured at the same drawdown. The figure of 8 is derived from the expression Logn(re/rw), which can only reach a maximum figure of 7 or 8. For instance, an 81/2” hole with a drainage radius of 1000 ft gives an Logn(re/rw) of 7.94. This also explains why a negative skin cannot exceed -8. e) Productivity Index From the slope of the IPR, the ‘Productivity Index’ (PI) can be calculated - it is a measure of the oil flow rate (bpd) that will be obtained for every psi of drawdown: for oil, measured as stock tank barrels of oil per day per psi of drawdown (stb/d/psi). A stock tank barrel is a surface barrel as opposed to a reservoir barrel. Oil will ‘shrink’ as it comes to the surface. In a good reservoir the drawdown leads to a far higher production rate ‘q’. Its productivity is greater, stated in bbls of oil per day per psi of drawdown PRODUCTIVITY INDEX P w 1000 800 Large Productivity index (Expressed as stb/day/psi for oil) This well will flow at 5100 bopd with a drawdown of 475 psi PI = 10.74 b/d/psi 600 400 ∆p = the drawdown the well is subject to the difference between the reservoir pressure and the bottom hole flowing pressure 200 PRODUCTIVITY INDEX Revision 2: 2001 Small Productivity Index This well will flow at 1100 bopd with a drawdown of 475 psi PI = 2.32 b/d/psi 1000 2000 3000 4000 5000 6000 Flow Rate, bpd 29 WELL PRODUCTIVITY AWARENESS SCHOOL PROCESS TYPE Fines Migration FLUID-ROCK INTERACTIONS RELATIVE PERMEABILITY REDUCTION PHYSICAL PORE SIZE REDUCTION Wettability change due to surfactant adsorption Clay Swelling Solids Invasion Adsorption/precipitation of large molecules (e.g. polymers) FLUID-FLUID INTERACTIONS Scale Formation Fluid saturation change Emulsion Formation and fluid block Sludge Formation PRESSURE/ TEMPERATURE CHANGE MECHANICAL PROCESSES Scale Formation Gas breakout Wax Formation Condensate banking Asphaltene Formation Water coning Stress-induced permeability change Perforation plugging FORMATION DAMAGE CLASSIFICATION BY PROCESS Tubing Gravel pack/ perforations Formation Scales Organic deposits Bacteria Silts and clays Emulsion Water block Wettability change TYPES OF DAMAGE AND WHERE THEY CAN OCCUR 30 Schlumberger Oilfield Review Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION PI = Q (Pr - Pw) In the radial flow equation it is possible to influence: 1. 2. 3. 4. 5. the reservoir pressure (e.g. by water injection). the bottom hole flowing pressure. the drainage radius (i.e. well spacing) the wellbore radius the skin factor f) What is the optimum Skin Factor? No skin factor is ‘optimum’. The table below shows some typical Skin Factors Situation Typical Skin Factor Badly damaged or partially completed well +500 Damaged well +2 to +20 Good initial completion – unstimulated +2 Lightly acidised 0 to -2 Typical deviated well -0.5 to Natural fractures or small propped frac -3 -3 +20 to to -1 to -5 Types of Formation Damage Within the definition of Formation Damage there are many mechanisms. These can be divided into two groups by the way in which the permeability is reduced: 1. Physical reduction in pore/pore throat size. a. b. c. d. e. f. g. h. i. j. k. l. Revision 2: 2001 Drilling mud solids invasion into the formation Drilling mud filtrate invasion into the formation Cement filtrate invasion (not deep/not serious if perforations good) Completion/workover solids invasion into the formation Completion/workover fluid invasion into the formation Perforation damaged zone Plugging of formation with native clays Asphaltene or paraffin precipitation in formation/perforations Scale precipitation in the formation/perforations Creation or injection of emulsion in/into the formation Growth or injection of bacteria Compaction of reservoir with production 31 WELL PRODUCTIVITY AWARENESS SCHOOL 2. Relative permeability reduction – reduction in the permeability to hydrocarbons in the presence of other pore-filling fluids. a. b. c. d. e. f. Water coning Condensate banking Wettability change Emulsion formation Fluid saturation change and fluid blocking Relative permeability changes If a well is damaged, it is not just a matter of ‘sucking it harder’ (increasing the drawdown) to achieve the required flowrates, because other factors may prevent this. In some fields, for instance, if the bottom hole flowing pressure is reduced too far the pressure drops below the ‘bubble point’ of the oil, and gas breaks out, causing production problems and a lowering of the efficiency of the well. In some fields there will simply not be enough pressure to overcome formation damage, and artificial lift may become necessary. In some countries there is a government limit to the amount of drawdown to which a well may be subjected. 32 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION INVASION OR STIMULATION IN NEAR-WELLBORE REGION • What happens if fluid invasion from the wellbore damages the permeability of the formation (top graph)? • What happens if fluids, say acid, cause an increase in permeability in the near wellbore region (bottom graph)? EFFECT OF ‘DAMAGE’ ON WELL PRODUCTIVITY Permeability reduction 1.0 20% 0.9 40% 0.8 60% 0.7 0.6 The well is producing at 50% of its undamaged capacity. 0.5 0.4 0.0 0.5 80% 1.0 1.5 2.0 2.5 Depth of altered zone (ft) EFFECT OF STIMULATION ON AN UNDAMAGED WELL 1.3 Permeability increase The well is producing 10% more than in its unstimulated state. 1.2 1.1 100% 80% 60% 40% 20% 0% 1.0 0.9 0.8 0.0 0.5 1.0 1.5 2.0 2.5 Depth of altered zone (ft) NOTE that in both the above graphs the damage or stimulation effect changes noticeably over the interval from zero to approximately 1.5 ft of invasion, after that the productivity ratio is little affected by further invasion. NOTE also that 'damage' has a far greater detrimental effect on productivity than 'stimulation' has a benefit. Revision 2: 2001 33 WELL PRODUCTIVITY AWARENESS SCHOOL UNDAMAGED WELL Production Rate 8910 stb/day Skin = 0 Open Hole No damage Fully Completed Vertical WASP-1: Our Typical Well, with rates calculated using the radial flow equation for oil SAME WELL WITH SKIN Production Rate 7130 stb/day Skin = +2 Open Hole Fully Completed Vertical SAME WELL WITH GREATER SKIN Production Rate 2850 stb/day Skin = +17 Open Hole Fully Completed Vertical In the above two examples we observe a skin of +2 and +17 respectively. At this stage we do not know what has caused the skin. It is necessary to investigate how the wells were drilled/completed/produced to investigate why there is this higher than expected pressure drop in the near-wellbore region, as compared with the ideal, open hole, fully completed, undamaged vertical well above. 34 Revision 2: 2001 O V E RVIEW OF WELL PRODUCTION Revision 2: 2001 35 WELL PRODUCTIVITY AWARENESS SCHOOL 36 Revision 2: 2001 DRILLING THE RESER V O I R Drilling the Reservoir Drilling Fluids 39 Types of Drilling Fluid Filter Cake Near Wellbore Permeability Reduction 39 40 42 a. Solids Invasion b. Filtrate Invasion 42 43 Depth of Invaded Zone 48 a. b. c. d. e. f. g. 48 49 49 49 50 51 Mud Formulation Open Hole Time Open Hole Size Overbalance Invasion Profile Calculation of Depth Calculation of Depth of Invasion vs Damage vs Skin Depth of the Damaged Zone Drilling Fluid Maintenance Revision 2: 2001 39 52 52 53 Fractures 55 Drilling Underbalanced 57 Coring 60 MODULE SUMMARY 63 37 WELL PRODUCTIVITY AWARENESS SCHOOL Primary requirements of a drilling mud To maintain borehole stability To minimise loss of fluid to the formation To suspend solids under static conditions To remove drilled cuttings from the hole To control formation pressure To lubricate the drill string To keep the bit cool Drilling Mud Classification Drilling Muds Oil based muds All Oil Muds Invert Oil Emulsion Muds Low Toxicity Synthetic OilOil Based Muds 38 Water based Muds Diesel OIl Polymer Muds Clay Inhibiting Glycol Muds Clay Muds Non Damaging Dispersed Non dispersed Revision 2: 2001 DRILLING THE RESER V O I R Drilling the Reservoir At the end of this module you should be aware of: • • • • • • Why formation damage can occur when drilling the reservoir The types of formation damage caused by various drilling fluids How to select a drilling fluid for a reservoir section The importance of natural fractures in reservoir formations The impact of mud damage on well productivity The maximum skin that invasion of mud filtrate can cause Drilling Fluids The potential for damaging the reservoir has started! As soon as the bit hits the reservoir, we can start to damage productivity! Before reaching the reservoir, the drilling team has only been worried about the suitability of the mud to drill the hole at an optimum speed, with an acceptable degree of safety, whilst providing an in-gauge hole suitable for wireline logging and a good cement job. Now that the reservoir is about to be entered, formation damage also needs to be considered . There must be a change from a $/ft mentality to a well quality mentality. A 'reservoir drilling' meeting should be held on the rig to clarify objectives, likely problems and possible solutions before drilling into the reservoir . Types of Drilling Fluid The type of drilling fluid used in a well depends on the well type. The expected lithology, well trajectory, bottom hole temperature and pressure all impact on fluid selection. Legislation nowadays also plays a part in fluid selection as oilbased muds are effectively banned in some areas. The many types of drilling fluids can be split into two broad categories: 1. Water based mud Covers a large number of fluids based on fresh water, sea water or brines; viscosified with bentonite or polymers. These systems can be ‘dispersed’ or ‘non-dispersed’, designed for shale inhibition, formulated for use at high temperatures and other specific requirements. Water based muds are constantly being developed to try to match the superior clay inhibition and lubricity properties of oil-based muds. The development of glycol and silicate muds is for this reason. Dispersants such as lignosulphonates also disperse formation clays and thereby mobilise fines. Avoid the use of dispersants if possible. Revision 2: 2001 39 WELL PRODUCTIVITY AWARENESS SCHOOL 2. Oil based mud (OBM) These do not have so many variations. They do not affect clays by salinity change, but surfactants in the mud can induce fines migration and/or relative permeability problems. Beware of using excess surfactants for this reason. Synthetic oil based muds have been developed to obtain the properties of OBM without the environmental drawbacks. These muds have only been partially successful since they themselves can pollute to a certain extent. What are the main functions of a drilling fluid? a) Cuttings transport b) Control of subsurface pressures c) Maintenance of hole stability d) Cooling and lubrication of the bit e) To minimise invasion of fluids into permeable formations In terms of well productivity we are primarily interested in ‘e’: the invasion of fluids into the formation. Items ‘a’ and ‘c’ are of some importance to well productivity since poor hole conditions could lead to a poor cement job with future consequences on the production from the well (see Section entitled “Completion Practices”). Drilling mud is a necessary evil: many reservoirs are susceptible to formation damage from the invasion of mud filtrate (or the chemical additives carried along with the filtrate into the near wellbore region). Why is the permeability reduced? Read on. Note : In this section, the concept of ‘Underbalanced Drilling’ is introduced to avoid the use of mud with an overbalance, and therefore prevent the invasion of fluids into the formation. Filter Cake When a well is drilled overbalanced (the common practice), the hydrostatic pressure of the mud is greater than the pore pressure - to ensure adequate well control. Hence there is a driving force for mud to enter the formation. Fluid loss from the wellbore occurs in two phases. When a formation is first exposed to drilling mud there is a high rate of fluid loss (known as the ‘spurt loss’ ) until a filter cake is formed. Once the filter cake is formed two types of filtration can occur: static or dynamic filtration. Static filtration is where the mud in the well is not being circulated; for example, when the pipe is out of the hole during logging. Mud solids build up against the formation until they form an impermeable barrier. The filter cake also compacts with time and becomes less permeable. The invasion of filtrate during static filtration is very small. Dynamic filtration , which accounts for most of the fluid lost, is where the mud is being circulated and the surface of the filter cake is 40 Revision 2: 2001 DRILLING THE RESER V O I R constantly being destroyed and renewed (pipe rotation/reciprocation would increase the erosion of the filter cake). An equilibrium condition leads to a constant rate of filtration (qcrit); that is at a steady mud circulation rate there will be a steady rate of filtrate invasion. Hydrostatic Pressure (P2 ) P2 > P1 External filter cake D R I L L S T R I N G Pore pressure (P1) (less than P2) Formation sand grain Hydrostatic pressure (P2) Internal filter cake FILTER CAKE As the mud is circulated past the borehole wall it partially destroys the mud cake. More filtrate enters the formation as more cake is temporarily built. This leads to a constant dynamic fluid loss. A 'rough' BHA with many stabilisers and Outside Diameter changes can also cause destruction of filter cake leading to greater dynamic filtration. LIMIT THE DESTRUCTION OF THE FILTER CAKE • Check the hydraulics; maybe alter them to be less aggressive • Check the Bottom Hole Assembly (BHA) used for drilling the reservoir; the more stabilisers the more the destruction of the filter-cake. • Consider changing the BHA just prior to drilling the reservoir, and drill the reservoir in one run without making a bit change. As a well is drilled, the shearing of the mud declines in steps, resulting in progressively thicker cake and lower values of qcrit. The formation is exposed to highly turbulent flow caused by jetting near the bit, then rapid flow opposite the drill collars, and finally laminar flow opposite the drillpipe. However, wellbores host a constantly changing environment. Under some conditions wall shear stress increases – for example following an increase in the pump rate or a change in mud properties. Experiments show that laminar flow of mud containing solids – such as barite particles, sand grains, or drilled rock chips – or turbulent flow of any mud is sufficient to erode the mud cake until a new equilibrium is established with a higher qcrit; [the more solids there are in the mud, and the faster you circulate leads to more (potentially damaging) filtrate invasion]. Revision 2: 2001 41 WELL PRODUCTIVITY AWARENESS SCHOOL 10 Spurt loss at bit face 10-1 Loss opposite stabilizers 10-3 Loss near bit (turbulent flow) Loss opposite drillpipe while circulating 10-5 Static filtration after pulling out of hole 10-7 30 sec 6 min 1 hr 1 day ~5 days 41 days Time History of filtrate loss rate into a permeable zone with a pie chart showing total invasion volume lost during drilling. Loss declines with time because shearing action at a given depth declines as the bit goes deeper. Most fluid loss (largest pie slice) takes place during dynamic filtration, when drillpipe is opposite the zone. STATIC FILTRATION VS DYNAMIC FILTRATION Schlumberger Oilfield Review Near Wellbore Permeability Reduction a) Solids Invasion Drilling fluids have a significant solids content (10 – 20% v/v) which cover a broad particle size distribution. The whole mud cannot usually invade into the formation as many of the particles are larger than the pore throat size in the rock matrix. Consequently a ‘filter cake’ is deposited on the surface of the rock. Even particles with a diameter of 1/3 of the average pore throat size can bridge externally. However, particles sized between 1/3 and 1/7 of the average pore throat size can enter the pore network and cause internal blocking. A Particle that is greater than 1/3 the size of the pore throat will plug. It will stop at the entrance. They form a filter cake. Should be produced back. FLUID HYDROSTATIC PRESSURE A particle that is between 1/3 and 1/7 of the size the pore throat will tend to BRIDGE. They will stop somewhere close to the wellbore. They are not easy to remove. They may have to be treated with chemicals. A particle that is less than 1/7 of the size of the pore throat will pass through (and back, hopefully) without plugging Formation Sand Grain PORE THROAT Formation Sand Grain PARTICLE SIZE VS. PORE THROAT PLUGGING 42 Revision 2: 2001 DRILLING THE RESER V O I R Solids plugging can dramatically reduce permeability, but due to the rapid entrapment of the solids and the build up of an external filter cake only a small amount of solids invasion occurs. Consequently damage from solids is usually very shallow (less than 2 inches) and is not normally important in perforated completions; but in non-perforated completions (see Section entitled “Completion Types”), solids damage can be very important. Hydrostatic Pressure 0 sec 2 sec 4 sec 6 sec 8 sec 63 sec reservoir of mud (concentrated clay particles) invaded core (brown denotes invasion of clay particles from the mud) Core core sample Spurt invasion in a very high permeability limestone (top) revealed in a series of time-lapse nuclear magnetic resonance scans at 2-second intervals. Color denotes water relaxation time and is interpreted to indicate concentration of clay particles: blue is highest concentration, brown to white decreasing concentration. The blue rectangle is a mud reservoir, situated at the top of the sample, indicated by an outlined rectangle. The scans show that clay particles invade the rock within seconds, and after 8 seconds little further change is observed. Simulations of spurt invasion (bottom) show pore bridging by mud particles (red) very close to the rock service. A few particles penetrate much further prior to bridging. Once the internal cake is formed, its composition is unlikely to change even if the mud solids composition is changed, for instance by adding barite. 25% 41% 50% Schlumberger Oilfield Review Porosity 'SPURT' INVASION OF SOLIDS Illustrated as nuclear magnetic resonance scans SEM studies have shown that plugging of just 15-20% of the pores and pore throats can cause significant damage. The solids will preferentially fill the most porous and permeable part of the formation first. Note that bentonite, a common constituent of drilling mud, can continue to hydrate for more than 24 hrs. If this goes on inside the rock matrix it may well block the pore space; therefore pre-hydration is always a good idea. b) Filtrate Invasion Once the filter cake has formed, it filters the mud so that only filtrate invades the formation – thus begins the filtration phase. Invasion , the process by which wellbore fluids leak off into permeable formations, is a necessary evil. To the reservoir engineer/petrophysicist, it impedes accurate formation measurements. To the drilling engineer, the filter Revision 2: 2001 43 WELL PRODUCTIVITY AWARENESS SCHOOL cake may assist in the maintenance of wellbore stability; but to all of us interested in well productivity the solids and the filtrate invasion represent potential formation damage. Shale particle Silt grain Pore-lining clay Quartz grain Authigenic clay Core Formation water bank Mud filtrate bank Undisturbed formation Wellbore Invasion Salinity front Water saturation, % Saturation front 0 Oil 100 Water volume fraction, % 0 Filtrate Formation water 100 Saturation/salinity fronts and fluid banks visualized as water-base filtrate invades water-wet, hydrocarbon-bearing formation. The microscopic schematics (top) illustrate the distribution of fluids in various types of pore geometries. Oil is green, formation water is blue and filtrate is orange. Schlumberger Oilfield Review FILTRATE INVASION Pictorial illustration of the invasion process In most reservoirs, mud filtrate is the main portion of the mud which invades to a significant distance. To cause damage, mud filtrate must adversely interact with either the reservoir fluids or the reservoir rock. In some cases this damage is ‘temporary’. Such damage may disappear when the filtrate is produced back with the early hydrocarbons; too often this is not the case. The filtrate causes damage by physical blocking of pores and pore throats or by changing relative permeability, for example: a) Swelling and Dispersion of Clays in the Formation Formation clays can swell when they are in contact with incompatible invading fluids, especially fresh water. This reduces the pore throat size and the permeability. Clay swelling is irreversible – they cannot be shrunk back! 44 Revision 2: 2001 DRILLING THE RESER V O I R Fresh water or low salinity solution will invade between the layers of the clay and cause them to swell. Layer spacing Before = 5 microns After = 50 microns Clay will swell SCHEMATIC ILLUSTRATION OF SWELLING CLAYS (Note - microscopic scale) As mentioned in the Rock Type Section, smectite clays are more prone to swelling than others. To reduce the swelling problems, use more saline muds, salts such as potassium chloride or encapsulating polymers. Potassium will cause clays/shales to swell the least. 100 Na+ 75 K+ Ca2+ In low salinity sodium brine a clay/shale will swell - the layer spacing will increase. The formation may be damaged if the clays now block the pore throats 50 25 0 0 10 20 30 40 50 Layer Spacing, 10-10 metres Montmorillonite is a smectite clay and very prone to swelling. CLAY SWELLING Montmorillonite - Expansion in Low Salinity Brine Chemically induced clay migration may occur if the invading fluid causes dispersion of formation clays. The movement of the clays may block pore thr oats. For most clays, dispersion only occurs when the salinity of the invading fluid is below a critical concentration (that of the native clay-wetting formation water), or chemical dispersants such as lignosulphonate are present in the filtrate. Siliceous fines can also be migrated by the invading fluids; the presence of dispersants or surfa c t a n t s i n c reases the likelihood of fines being liberated . If you have these in the mud, experiment in the laboratory to find the minimum concentration necessary. Note that the clays within a sandstone may not swell enough to cause drilling problems (e.g. tight hole, sloughing), but unbeknown to the driller their growth may be seriously impairing future productivity. Thus the mud engineer and all other concerned parties should ensure that an inhibited fluid is used to drill through any reservoir that may have swelling clays, even if it is not flanked by problematical shales. Revision 2: 2001 45 WELL PRODUCTIVITY AWARENESS SCHOOL Single Phase Flow (water) (Low Rate) (High Rate) Flow SAND Flow Pore Throat Plugging Fines Fines If fines or clay particles are mobilised they stand a better chance of flowing out of the formation without bridging if the well is brought on stream slowly. Flow Oil flow after Low Rate Cleanup Oil Flow Immobilized Fines contained in water permeability around sand grains Flow Oil Flow Sand Grain Interstitial Water FINES OR CLAY PLUGGING Flow of Water Wet Fines (after Kreuger) If clays and/or fines are mobilised they may be produced out with the hydrocarbons. If the well is brought on stream at a controlled slow rate, there is less likelihood of the debris plugging the pore throats. Some muds react adversely with cement and viscosify alarmingly. This may be happening within the formation due to a reaction with calcium. Bearing in mind the 'reverse funnel' effect: what goes in may not come out. Check to see if your mud filtrate reacts with calcium (in this formation?) to cause a viscous blocking effect. Return permeability tests are the best way to see if a mud filtrate will damage a formation. The permeability of a preserved core from the reservoir is measured, prior to a sample of the mud filtrate being forced through the core under pressure. The core is then flushed with hydrocarbons to simulate production and the return permeability measured. This is a very important measure of checking the damage potential of your mud. It could save you millions of dollars in a field development. Do several tests with several cores. b) Scale Precipitation If incompatible formation water and mud filtrate are mixed, scale can precipitate – this can restrict or block pores. A knowledge of the chemistry of the formation water and the drilling fluid will assist in the prevention or identification of scale. The most common scales are insoluble sulphates and carbonates; namely calcium and barium salts. Sea water has a high sulphate content and should not be used in reservoirs where scale precipitation could be a problem. In a formation containing barium, even tiny amounts of seawater can cause irreversible damage due to barium sulphate precipitation. 46 Revision 2: 2001 DRILLING THE RESER V O I R Na+ Insoluble salts will plug the formation. If you inadvertently mix a mud chemical with a formation chemical that results in a red cross or a brown tick here, you will be damaging the formation. K+ Barium is frequently found in formation waters. Ba2+ Mg2+ Ca2+ OH - Cl - HCO3- CO32- SO 42- ✓ ✓ ✗ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✗ ✗ ✗ ✓ ✓ ✓ ✓ ✗ ✓ Soluble ✓ Slightly soluble Sulphate is found in seawater. Use seawater indiscriminately in the drilling mud or the completions fluid and insoluble barium sulphate will precipitate in the formation ✗ Insoluble SOLUBILITY OF COMMON INORGANIC SALTS c) Fluid Saturation Changes The invading fluid can change the original fluid saturation, and hence the permeability to oil; at worst it can cause ‘fluid blocks’. Damage due to relative permeability changes is often a temporary effect; however, the higher the viscosity of the invading fluid the longer it will take for the initial permeability to be recovered. In a long interval it may prove difficult to clean-up all of the section and parts of the reservoir may never produce as the oil/gas will preferentially channel through the cleaned-up zone only. 1.0 0.9 ● Relative permeability to oil. 0.8 As the amount of fluid invasion increases, so does the water saturation. As the water saturation increases the relative permeability to oil decreases, ie. the oil has more difficulty in flowing out of the formation. The formation is ”damaged”. 0.7 kro 0.6 0.5 Connate water saturation. Formation water inherent to this rock. It wil never go below 27% in this particular formation. Such water may be found bound to sand grains for instance. 0.4 0.3 0.2 krw ● 0.1 ● ● 0.0 0.0 0.1 0.2 0.3 0.4 ● ● ● ●● ● ● ● ●● 0.5 0.6 ● ●● ●● ● Relative permeability to water. ● ●●●● 0.7 0.8 0.9 1.0 Residual oil saturation. In this particular formation, there will always be a minimum of 23% oil, where the rock is oil-bearing. The mud filtrate cannot flush away this oil. Water saturation, fraction pore space FORMATION DAMAGE DUE TO FLUID SATURATION CHANGE Oil-Water Relative Permeability The effective permeability to oil is reduced if the wettability of the rock surface is changed from water-wet to oil-wet. The majority of reservoir rocks are originally water-wet due to their sedimentary nature and the depositional environment in which they were formed. Carbonate reservoirs can be oil-wet or both oil- and water-wet (mixed wettability). Revision 2: 2001 47 WELL PRODUCTIVITY AWARENESS SCHOOL Formation damage can therefore occur if the invading fluid can change the wettability of the rock. Oil based muds contain surfactants in the mud filtrate, which can cause wettability changes. Corrosion inhibitors in completion brines, or in acid stimulation fluids; can also cause this problem. An oil-based mud in a water-wet gas sand can cause problems with relative permeability changes; therefore careful research should be done before using this combination. d) Chemical Adsorption Adsorption of polymers onto the rock matrix can also cause formation damage, due to pore size reduction. This is most likely to happen in water based muds. e) Emulsion Production Mixing of formation water with the mud filtrate can create emulsions. These emulsions are viscous and may significantly reduce permeability by pore blocking. The formation of an emulsion generally requires high shear rates for effective mixing; thus emulsions are not generally a problem with drilling muds invading a formation. Depth of the Invaded Zone Several factors control the amount of filtrate lost to a formation: Higher circulation rates = more invasion Large + changing BHA = more invasion 2001 5 12 19 26 6 13 20 27 7 14 21 28 1 8 15 22 29 2 9 16 23 30 3 10 17 24 31 4 11 18 25 Borehole dynamics Overbalance Open Hole Time More time – More invasion Filter cake permeability Open hole size Larger bit size gives larger area to invade Invasion profile: cylindrical not conical FACTORS AFFECTING THE DEPTH OF THE INVADED ZONE DO EVERYTHING YOU CAN TO LIMIT FILTRATE INVASION IN THE RESERVOIR a) Mud Formulation The filtration rate must be controlled, both to minimise potential formation damage and to minimise drilling problems such as tight hole and stuck pipe. Fluid loss additives are used to produce thin, low permeability filter cakes. Filter 48 Revision 2: 2001 DRILLING THE RESER V O I R cake permeabilities are typically 100 to 100,000 times less than reservoir permeability. The filter cake usually controls the rate of invasion, independently of formation permeability. Formation Permeability (mD) 100 10000 10 1000 1 100 0.1 10 0.01 1 0.001 0.1 0.0001 0.00001 0.000001 0.0001 0.01 1 Filter Cake Permeability 100 (mD) Most filter cakes have permeability in this region. The invasion rate is therefore fairly independent of the formation permeability. INVASION RATE VERSUS FILTER CAKE PERMEABILITY b) Open Hole Time The amount of fluid lost will be greater if the filtration process occurs for a longer time. The longer the mud is circulated in open hole the more fluid will invade. Apart from the money saved on rig time, this is another argument for limiting check trips and unnecessary circulating on bottom. LIMIT OPEN HOLE TIME – RESERVOIR EXPOSURE c) Open Hole Size The rate of filtrate invasion also depends on the ‘filter area’ available. The larger the hole size, the greater the rate of loss. Hole size should not be ignored – check the caliper logs. d) Overbalance This is the driving force for the filtration process. However the filtration rate does not increase linearly with overbalance. For water-based muds it is thought that invasion rates are fairly independent of overbalance above 500 psi, due to compression of the filter cake. Revision 2: 2001 49 WELL PRODUCTIVITY AWARENESS SCHOOL In water-based muds there is a very slight increase in filtration rate with increased overbalance. OBM 1000 psi 0 0 ∆p Differential Pressure Increasing IMPACT OF OVERBALANCE ON INVASION RATE e) Invasion Profile The profile of invasion will be fairly uniform along the well. The invasion of filtrate will fill up pore space, and the further from the well it goes, the more pores there are to fill. Thus the invasion profile is generally cylindrical not conical. The shallow and deep reading wireline resistivity tools record the cylindrical invaded zone after drilling has ceased. The permeability of the rock does not normally affect the invasion profile because invasion is controlled by the much lower permeability of the filter cake. Solids Invasion Filtrate Invasion High Porosity Medium Porosity This diagram assumes that each of these sand layers is the same thickness, and that the same volume of fluid has invaded each layer. Low Porosity INVASION PROFILE 50 Revision 2: 2001 DRILLING THE RESER V O I R f) Calculation of Invasion Depth In non-fractured reservoirs a calculation can be made of the depth of invasion if the volume of mud lost downhole whilst drilling the reservoir is known. The volume lost is the filtrate that has invaded the formation. Vol inv = (1 − Sor )h( rs2 − rw2 ) Where, Volinv φ Sor h rw rs = = = = = = Volume of invasion in cubic feet Average formation porosity (fraction) Residual Oil Saturation (fraction) Height of formation in feet Radius of wellbore in feet Depth of invasion in feet (measured from centre of wellbore) Note: 1 bbl = 5.6148cuft. The following table shows the volume of invasion (in barrels) per 100ft of formation, for a range of porosities and invasion depths. The figures below do not take into account the residual oil saturation. Porosity (%) 0.2 0.5 1 Depth of Invasion (feet) 2 5 10 20 50 2781 3708 4635 5562 17024 22699 28374 34049 Filtrate Loss Volume (bbls/100 ft of formation) 12 16 20 24 1.2 1.6 2.0 2.4 4.1 5.4 6.8 8.1 11.5 15.3 19.1 22.9 36.4 48.5 60.6 72.7 191.6 255.5 319.4 383.3 719.0 958.7 1198 1436 8.5 inch wellbore Excluding losses to fractures, it is clear that an invasion depth of 50ft is inconceivable – it would take more than 20,000 barrels of fluid to be lost downhole every 100ft! In reality, less than 1000 barrels of mud is usually lost throughout an interval (including surface losses). Hence, an upper limit of 5 feet can be used for most practical purposes BP studies estimated filtrate invasion to be between 12 and 24 inches. In exceptional cases the invasion can go deeper than 5 ft. If possible, try and calculate the fluid losses whilst drilling the reservoir (use the mudloggers). Using the calculation you might be able to crudely estimate the depth of invasion. By doing so, you will have a better idea of the impact of filtrate invasion on well productivity and how deep the perforations must go to get past the damage. Revision 2: 2001 51 WELL PRODUCTIVITY AWARENESS SCHOOL g) Calculation of Depth of Invasion vs. Damage vs. Skin The skin factor for damage caused by filtrate invasion in a vertical open hole well is defined as: where S = (k/kd-1) Logn(rd/rw) kd = permeability of damaged region rd = radius of damaged region (measured from centre of wellbore) rd rw kd = permeability of damaged region NEAR WELLBORE DAMAGE This equation can be derived from the radial flow equation. Note that the magnitude of the skin is dependent on: 1. the ratio of the undamaged to the damaged permeability, i.e. to how damaging the mud is. 2. the depth (rd-rw) of damage, i.e. the ‘fluid loss’ of the mud. To calculate the reasonable upper limit of damage due to filtrate invasion, imagine 3 ft of invasion. If this filtrate was 90% damaging (i.e. reducing a permeability of 100 mD to 10 mD) then the above formula would give a skin of +20. This illustrates that the maximum possible skin from filtrate invasion in reality is approximately +20. Any skins much higher than this must also have an element of completion skin (see Section on “Completions”). Depth of the Damaged Zone The depth of the damaged zone is not necessarily the same as the depth of the invaded zone. Firstly the invading fluid may be non-damaging; thus the log analysts may witness a deeply invaded zone, yet formation impairment may be minimal. 52 Revision 2: 2001 DRILLING THE RESER V O I R Secondly, if the formation damage has been caused by incompatible water, the damaged zone will be the same as the invaded zone, since the supply of damaging fluid is constant. However if the damage is caused by a surfactant in a mud, then the near wellbore formation will adsorb the surfactant and the deeper invading fluid will be less-damaging. Well A Well B Invaded Zone Any formation damaged caused by solids will not be the same as the invasion depth Damaged zone here is equal to invaded zone since damage was caused by incompatibility of mud filtrate with formation water Damaged Zone Solids Zone Damaged zone is less than Invaded zone here, since damage is due to surfactant in an oil based mud – which is consumed and depletes DEPTH OF THE DAMAGED ZONE Drilling Fluid Design/Maintenance The subject of mud maintenance is too large to be covered in these notes, given the huge variety of mud types that exist. However some general comments can be made for drilling fluids used for the reservoir interval: • Consider whether the mud needs to be different across the reservoir as compared with the sections above. • Check both API fluid loss and HTHP fluid loss. Minimise through the reservoir. • Keep solids content as low as practicably possible. • Keep the mud simple – the less that is in there, the less that can damage. For instance, if a chemical additive has been necessary higher up the hole, try to remove it before reaching the reservoir. • Be aware of the potential formation damage problems. • Don't change the mud from the formula designed and tested to optimise return permeability. • Consider changing out the mud to drill the reservoir – this may be an economically viable alternative given the financial implications of formation damage and loss of productivity. Remember to treat the reservoir differently from all that has been drilled above. Switch from a $/ft mentality to a QUALITY mentality. Revision 2: 2001 53 WELL PRODUCTIVITY AWARENESS SCHOOL RELATIVE MERITS AND DAMAGE POTENTIAL OF DRILLING FLUIDS 54 Revision 2: 2001 DRILLING THE RESER V O I R Fractures Some reservoirs, notably carbonates, have a very low matrix permeability, and production depends on flow through a network of microfractures and fractures. The fractures are mostly less than 10 microns in width, but may be much wider. Because of the uncertainty of fracture size, and because of the geometry involved, bridging fractures is more difficult than bridging porous media. If the fractures are not bridged, fine mud particles invade the fracture and filter internally against the sides of the fracture until it is filled with mud cake. Such internal mud cakes are not easily removed by backflow, and productivity is greatly impaired. Such reservoirs must therefore be drilled with a fluid whose solids are degradable, or that can be destroyed by acid (calcium carbonate) or low salinity fluids (sized salts). A fractured formation is a good formation. It may be difficult to drill, but by the same token it is easy to produce – provided that the fractures have not been blocked by mud! Geologists go looking for fractures in field developments; the extent of fracturing can make or break a field development. The fractures created back in geological time may have been filled at a later date by geological fluids depositing other rocks such as calcite, which would make fractures impermeable and of little use to oil production. The illustration below shows how fractures can occur naturally in geological time. Fracturing in a folded bed Cross fracture Oblique fractures Longitudinal or strike fracture Whole mud losses downhole can only occur to naturally fractured or vuggy formations (unless the drilling mud is too heavy or the Equivalent Circulating Density [ECD] too high, and fractures are induced in the formation). Mud solids or Lost Circulation Material (LCM) can penetrate into fractures to a much greater depth than the perforations will reach giving very high skin factors. Revision 2: 2001 55 WELL PRODUCTIVITY AWARENESS SCHOOL Beware of inducing factures – Mud weight or ECD too high Invasion/Damage will be deeper than perforations can reach – Use soluble LCM if possible Try to identify fractures whilst drilling – Mudloggers + drillers to monitor mud losses accurately – (down to 1bbl or less) – Keep detailed record – (importance may only be evident at a later date) - Drillstring vibrations Design completion to suit fractures FRACTURES Production from fractures can dominate the productivity of a well, especially in low permeability formations. It is therefore vital that any fractures are identified. Some fractures are observed in wireline logs and cores; however a vital piece of information can be the mud log; where the mud loggers should observe and record even the slightest mud loss. The fractures usually become plugged and may not be seen on wireline logs or initial testing. Mud Losses 1900 2000 The mudloggers observed a two barrel mud loss at this depth. Initial DST Post-Acid DST 55 2 25 0 0 16 0 4 1 0 0 0 0 92 2100 Post acid test indicates that natural fractures have been cleaned up and dominant production is from this level. 1 350 bpd 6640 bpd IMPORTANCE OF PRODUCTION FROM CONDUCTIVE FRACTURES Note that fractured zones of fields are difficult to predict and map; therefore any help that the drillers can give to the geologists is most welcome. If there are natural fractures in your well it is imperative that your perforation design takes this into account, so that you connect the natural fractures to the wellbore. 56 Revision 2: 2001 DRILLING THE RESER V O I R Drilling Underbalanced If a well is drilled with a hydrostatic head that is less than formation pressure, then mud solids, cuttings or fluid will not invade the formation, thus formation damage is avoided. The primary device that is needed is a rotating blowout preventer or a rotating control head used also for air/foam drilling. Rotating BOP specifications Maximum static pressure Maximum pressure while drilling Optimum working pressure while drilling Working pressure while stripping Maximum rotating speed Through bore without kelly packer insert Side port outlet flange BOP stack flange mount 2,000 psi 1,500 psi 1,000 psi 1,000 psi 100 rpm 11 in. 71/16 in., 5,000 psi API 11 or 135/8 in., 5,000 psi API Kelly or drillpipe Kelly or drillpipe Seals Bearing assembly Quick change packer assembly Inner packer Hydraulic fluid Outer packer Bearing Mechanical seal Stripper rubber Mudflow Tool joint Mudflow Tooljoint ROTATING HEAD SCHEMATIC ROTATING BLOWOUT PREVENTER SCHEMATIC The practice of underbalanced drilling or ‘flow drilling’ allows wells to flow oil and gas through the choke line at a controlled rate whilst drilling ahead. The rotating BOP has been developed to handle up to 1500 psi of surface back pressure whilst drilling with air, gas, nitrogen, foam, water or light fluids. One of the problems with drilling with jointed drillpipe through a rotating head or BOP, is the pressure limitation of the seal around the pipe. Revision 2: 2001 57 WELL PRODUCTIVITY AWARENESS SCHOOL PRESSURE RATINGS Rotary rig/rotating head Rotary rig/rotary BOP Coiled Tubing Drilling Continuous Duty Pressure Rating (psi) 1000 1500 5000 A well is often brought under primary control – an overbalance is established – when a bit is tripped. This leads to losses into the formation, which is not protected by a filter cake. The overbalance during tripping is necessary for safety and because it is time consuming and wears the sealing elements to strip an external upset jointed drillstring. Whilst under-balanced drilling is advantageous for the reservoir and other factors detailed earlier, it does have the complication of not being suitable for 'heaving' or 'sloughing' shales that need hydrostatic pressure to keep them in check. Therefore if there are such formations above the reservoir they must be cased off first before drilling underbalanced. Underbalanced drilling is being used primarily in pressure depleted reservoirs which have strong reservoir rocks with a minimal risk of wellbore collapse. In Canada, the practice of underbalanced drilling is widespread; indeed reservoirs are often drilled with the well flowing! The cash flow can pay for the well. OPERATIONAL REQUIREMENTS (PATENTS PENDING) Flarestack Gas Liquids Solids 3 Stage Separator Sample Catchers Top Drive System/ Power Swivel Oil Tanks Nitrogen Pumper Water Tanks/ Kill Tank R-BOP/ Double Ann Choke Manifold System Nitrogen Pumper Drilling Fluid Tank Rig Pumps Cutting Returns Northland Production Testing Ltd. 58 Revision 2: 2001 DRILLING THE RESER V O I R Fluid Selection • Clear fluids used; occasionally with polymers to assist hole cleaning. • Underbalanced drilling without gas lift is possible with water down to 8.34 ppg and oil down to 6.95 ppg. Below this density requires drilling with foam, mist or air unless the well has a high GOR. • Clear fluids are preferred due to reduced wellbore damage if lost circulation or imbibition does occur. • If a well is flowing oil whilst drilling with a polymerised foamed fluid there is a risk of emulsions forming. • Directional measurements via MWD through the drilling fluid are possible with water, oil or gas lift. If foam is used, the connection has to be wireline (possible in coiled tubing). • Reservoir pressure needs to be accurately known, to calculate underbalance, taking into account cuttings loading, friction pressures etc. Potential Difficulties • Spontaneous Countercurrent Imbibition: capillary pressure may cause movement of fluids from the wellbore into the formation despite the underbalance. Possible damage. • Hydrogen Sulphide (if present): if well is flowing, H2S comes to surface. • Wellbore Stability: Not well understood. Rule of thumb states that if hole porosity is greater than 30% the rock may not be stable enough to be drilled underbalanced. • An overbalanced fluid has to be put in place to log the well – unless run on coiled tubing through pressure equipment. Rewards Alaskan examples: Well I – offset well drilled overbalanced = – underbalanced (CT) drilling = Reference: Revision 2: 2001 1200 bopd 4000 bopd Well II 1500 4600 Underbalanced Drilling With Coiled Tubing and Well Productivity. L.J. Leising and E.A. Rike, Dowell Schlumberger. SPE 28870 . 59 WELL PRODUCTIVITY AWARENESS SCHOOL Coring Coring can be time consuming and expensive – but it is very important. Cores are not just in the domain of the geologist and the reservoir engineer; all parties interested in well productivity should be interested in the core. AIR CORING Air Coring uses standard coring equipment with specialised core bits and modified operating techniques. The difference between air coring and conventional coring is that the drilling fluid is air, air mist, or foam rather than a liquid mud. Coring and wellsite core handling should follow the best possible practices because the value of all core analysis is limited by this initial operation. The major problems encountered during coring, handling and preserving reservoir rocks are: 1. designing a bottomhole coring assembly and drilling fluid programme to minimise mud invasion and maximise drilling parameters 2. selecting a non-reactive core preservation material and method to prevent fluid loss or the absorption of contaminants (e.g. wettability altering drilling fluid components) 3. applying appropriate core handling and preservation methods based on rock type, degree of consolidation, and fluid type There is not one best method for handling and preserving cores. Core preservation is an attempt to maintain core before analysis, in the same condition 60 Revision 2: 2001 DRILLING THE RESER V O I R that existed when it was removed from the core barrel. Rock types that require special procedures for coring and wellsite preservation are: • • • • • • • unconsolidated rocks - both heavy and light oil vuggy carbonates evaporites fractured rock rocks rich in clay minerals shale low permeability rock (tight gas sand) There are many ways to preserve core and all should be investigated to find the most suitable. Freezing of cores is the most common and perhaps controversial method of preserving cores; whatever its potential difficulties and problems it is the only way of preserving and handling unconsolidated rock for core plugging. Before a coring job, assemble a multi-disciplinary team • drillers • drilling engineers • reservoir engineers • geologists • core analysts • mud loggers/core catchers Discuss all aspects of the job early on in the planning stage. Draw up detailed procedures and have a step-by-step programme available on the rig. The better your core - the better the core evaluation – the better the results – the higher the future well productivity. Good cores are vital for return permeability tests to help the choice of drilling fluid to find the one that is least damaging. Revision 2: 2001 61 WELL PRODUCTIVITY AWARENESS SCHOOL WASP-1 Same Well with Filtrate Invasion Same Well with Greater Depth of Invasion Production Rate 8009 bopd Skin = +0.9 Production Rate 7665 bopd Skin = +1.3 Open Hole 40% Permeability Reduction 1 Foot of Invasion Filter Cake Removed Fully Completed Vertical Same Well but with Greater Damage Same Well with Greater Damage to a Greater Depth Production Rate 5320 bopd Skin = +5.4 Production Rate 4570 bopd Skin = +7.6 Open Hole 80% Permeability Reduction 1 Foot of Invasion Filter Cake Removed Fully Completed Vertical 62 Open Hole 40% Permeability Reduction 2 Feet of Invasion Filter Cake Removed Fully Completed Vertical Open Hole 80% Permeability Reduction 2 Feet of Invasion Filter Cake Removed Fully Completed Vertical Revision 2: 2001 DRILLING THE RESER V O I R Revision 2: 2001 63 WELL PRODUCTIVITY AWARENESS SCHOOL 64 Revision 2: 2001 COMPLETIONS Completions History 66 Completion Types 67 Well Design Multilateral Wells Geosteering Completion Design 67 71 76 77 a. Open Hole Completion b. Uncemented Liner c. Cased and Perforated 78 78 79 Completion Practices 80 Casing and Cement Completion Fluids 81 83 a. Types b. Importance of Cleaniness/Filtering c. Displacement 84 84 87 Perforating 87 a. b. c. d. e. f. g. h. History of Perforating Perforating Charges Delivery Systems Perforating Skin Perforating Through Drilling Damage Perforation Tunnel Length Underbalanced Perforating Overbalanced Perforating Sand Control a. b. c. d. Internal and External Gravel Packs Sand Control Using Chemical Methods Frac-Pack Cleanliness MODULE SUMMARY Revision 2: 2001 66 88 88 90 91 94 94 96 100 105 105 109 110 112 119 65 WELL PRODUCTIVITY AWARENESS SCHOOL Completions At the end of this module you should be aware of: • • • • • • The main types of completions used When zonal isolation is important and how it is achieved Why special completion fluids are used How wells are perforated Typical skin factors associated with the main completion types How high skins can result from mud damage combined with a completion skin In this module we will discuss 'the completion' as the overall design for maximising the well productivity. We are not concerned here with the selection of tubing, packers, tubing accessories and artificial lift methods. Well Design: VERTICAL – DEVIATED – HORIZONTAL Completion UNCEMENTED Barefoot CASED AND CEMENTED PERFORATED Gravel Pack Fracture stimulation Pre-packed screen Uncemented Liner Gravel-pack Natural PRODUCE THE WELL COMPLETION TYPES History The first oil wells were drilled vertically and completed ‘barefoot’; that is without casing. Completion methods were very crude. Early photographs of discoveries in the USA show plumes of oil gushing from wells. When the initial surge of ‘black gold’ had died down or been suppressed, the 'completion' of the well simply meant it was capped with a valve and the discovery put on production. 66 Revision 2: 2001 COMPLETIONS In those early days the science of reservoir engineering was in its infancy and formation damage was not something that most of the ‘wildcatters’ knew about or worried about. As the business of oil well drilling progressed, more and more wells were completed with a cemented string of casing, and the casing perforated to establish communication with the formation. This was found to be beneficial to long term production. Sand control problems led to the emergence of gravel packing and sand consolidation treatments. Tubing Casing goes back to the surface Casing Liner hanger Liner does not come back to surface Shoe Packer Cap rock Oil Zone Cement sheath Barefoot Completion Open hole Screen Liner Completion Cemented liner (perforated) Completion Cemented Casing Completion COMPLETION PRACTICES Deviated wells were drilled for a variety of reasons, but principally to develop offshore fields from platforms. Although horizontal wells were first attempted in Russia in the 1950’s, it is only in fairly recent times that there has been a major move to drilling horizontal or high angle wells in some reservoirs. Many of these horizontal or high angle wells have reverted to the ‘old’ methods of completing wells barefoot or with uncemented liners, be they slotted or perforated. More modern hardware, such as wire-wrapped screens, or pre-packed screens can also be run. Completion Types Well Design Leaving aside the necessity of a platform well to reach a certain distant part of the reservoir, a well can be vertical, high-angle or horizontal as part of the overall completion design. Revision 2: 2001 67 WELL PRODUCTIVITY AWARENESS SCHOOL A vertical well is the easiest to drill, but a high angle or horizontal well may be beneficial for productivity. When there is no formation damage a high angle or horizontal well should have a negative skin. However, if you do damage such a well during drilling or completing then positive skins will result. Vertical Well cheapest simple to operate optimum design for hydraulic fracturing Reasons For Drilling Horizontal wells To avoid water trying to cone ideal for homogenous thick reservoir to drain thin reservoir to drain oil rim to minimise drawdowns minimise wells required for field development fractured reservoirs To effectively drain high permeability layer (or thin reservoir). Reasons For Drilling High Angle Wells to more effectively drain an anisotropic reservoir To effectively drain a lensed reservoir. to minimise wells required for a field development WELL DESIGN A horizontal well is particularly suited to the following developments: • Thin reservoirs, or thin oil columns, where the Kv/Kh (vertical/horizontal permeability) ratio is not too low, and there are no significant barriers to vertical permeability (e.g. shale streaks), 68 Revision 2: 2001 COMPLETIONS • Reservoirs prone to water coning or gas cusping, • Reservoirs prone to sand production, • Where reservoir quality varies laterally and a horizontal well gives a better chance of finding ‘sweet spots’, • In combination with extended reach drilling and geosteering, to drain different reservoir blocks, or reservoirs, in one well, • In fractured reservoirs, where a horizontal well gives a better chance of intersecting fractures, and • In combination with extended reach drilling, to develop fields in environmentally sensitive areas, or from an offshore platform, where the number and surface location of wells is severely restricted. High angle wells (over 75 deg.) can be used for many of the same purposes as horizontal wells, but additionally are suitable for : • Thick reservoirs where the Kv/Kh (vertical/horizontal permeability) ratio is low, and/or there are significant barriers to vertical permeability (e.g. shale streaks), • Lensed reservoirs, and • Layered reservoirs. Common sense, and field experience, show that horizontal wells generally produce much more than vertical ones, due to the greater area of sand-face exposed. Obviously the radial flow equation for vertical wells does not apply to horizontal wells, so a different approach must be used to estimating the flow from horizontal wells. In a 1984 SPE paper, Giger, Reiss and Jourdan presented an analytical approach to estimating the inflow performance of horizontal wells. Their ‘horizontal well inflow performance’ algorithm was accompanied by an equation to allow the ‘Productivity Ratio’ of a horizontal well to be estimated. This, the ratio of the productivity index of a horizontal well to that of an otherwise similar vertical one, increases with the length of the horizontal section. Giger et als basic algorithm incorporated a number of simplifying assumptions, including : • • • • • Zero skin/formation damage, Vertical and horizontal permeabilities the same, A homogeneous and isotropic reservoir, Uniform contributions from all parts of the perforated interval, and A uniform draw-down across the completed interval. Giger et al provided a modification to allow for differences between vertical and horizontal permeability, and this allowed their approach to be used extensively for analysing horizontal well productivities in the 1980's. However, for the wells with much longer horizontal sections now common, often in situations where none of the above assumptions would be reasonable, Giger et als approach is of limited use. With, according to one estimate, one in five new wells being drilled horizontal, a good understanding of the inflow performance of horizontal wells is very Revision 2: 2001 69 WELL PRODUCTIVITY AWARENESS SCHOOL HORIZONTAL WELL The Vertical Well in the same reservoir produced only 8910 bopd Production Rate 14260 bopd Skin = -3 ❏ ❏ ❏ ❏ ❏ ❏ Open Hole 40% Permeability Reduction 2 Feet of Invasion Filter Cake Removed Fully Completed 2500 ft Horizontal Section Note: Do not worry if you cannot understand all the complicated equations. It is more important that you understand the principle; that a horizontal well will produce more than a vertical well, all other factors being equal. important, for example when deciding whether to develop a field with vertical or horizontal wells. Though the analytical approach, pioneered by Giger et al, is of limited use in predicting well productivities, it is still useful for sensitivity analysis and ranking. Where there is sufficient reservoir data, and man-power and budget, reservoir simulation on a computer, also applicable to analysis of multilateral well projects, is often used. Where a number of horizontal wells have already been drilled in an area, the performance of these wells may provide a good estimate of the productivity of the next one. The effect of formation damage in horizontal completions has, in the past, been commonly ignored, both because of the much higher productivity of horizontal wells and because it is impossible to obtain a unique estimate of skin from a horizontal well test. However, production logging is now often used together with well tests to get some idea of which parts of a horizontal well bore are contributing effectively and which not, and, hence, which parts of the formation are damaged. BP companies now place increasing emphasis on the avoidance of damage and sand-face/perforation clean up of horizontal well bores. Productivity prediction remains very imprecise for any single horizontal well. Recent examples include a field where 30% of the horizontal wells one area performed no better than vertical wells and, also, one horizontal well where water broke through after only one week, compared with a predicted two years. However, with ‘productivity ratios’ typically in the range of 2 to 4 for conventional reservoirs, up to 6 to 12 for fractured reservoirs, compared with ‘cost ratios’ typically in the range of 1.5 to 4, interest in horizontal wells, and in understanding their performance, can only intensify. 70 Revision 2: 2001 COMPLETIONS PRODUCTIVITY INDICES RATIOS HORIZONTAL AND VERTICAL COMPLETIONS Completion Interval Length (feet) Productivity Ratio Horizontal/Vertical (J h /J v ) 100 200 400 800 1000 1.5 2.1 3.4 4.7 5.7 Reservoir radius (re) = 933 feet Formation thickness (h)= 50 feet Drill hole radius (rw) = 0.33 feet Homogeneous formation, Single phase flow Multilateral Wells a) Summary In a similar way to horizontal wells, multilateral wells increase well productivity primarily by increasing the length of the reservoir section exposed in a well. Other beneficial effects include the possibility of draining more than one reservoir, or more than one block within a reservoir, from one well. A ‘multilateral’ well, is one with one or more laterals, that is one or more subsidiary well-bores off the main well-bore. Laterals are usually horizontal or highly deviated, and may be drilled as part of the initial drilling programme for a well, or as a later deepening or work-over project. Though the first multilateral well was drilled in California in the 1930’s, it is only in the past few years that multilateral drilling and completion technology has developed to the point where a range of sophisticated drilling, casing, cementing and completion options are offered by service companies. Though under development, no currently available system provides a pressure-tight seal, independent of cement and of the completion, at the junction between the main well bore and the lateral. Though recently available from service companies, most multilateral completions installed to date do not permit selective re-entry, through the completion, via coiled tubing to laterals. Without this selective reentry, attempts, for example, to circulate drilling mud out of a lateral are reduced to ‘poke and hope’ with coiled tubing; something that is not always successful! Selective re-entry permits a range of intervention techniques to be applied, again using coiled tubing, so, for example, a lateral producing water can be plugged off, to allow dry oil to be produced from a well that might otherwise have a high water-cut and perhaps not flow at all without a pump. The record for the number of laterals in one well is probably ten, drilled by the Russians as long ago as 1953, with similar wells being drilled in the USA in the late 1980’s. However, such older multilateral wells were usually completed openhole, with little or no possibility for re-entering the laterals. Though open-hole Revision 2: 2001 71 WELL PRODUCTIVITY AWARENESS SCHOOL Conventional Wells Multibore/Lateral Well Well 1 Well 1 Well 2 Well 2 completions are still common, for example currently at Wytch Farm, wells with cased and cemented laterals more usually have one or two laterals only, that is in addition to the primary well bore. This may also be producing, or have been plugged off through the reservoir if the laterals were drilled from an old wateredout well, for example as at FA 1-2, in the Forties field in the North Sea. This well was re-entered by BP in 1996, and side-tracked out of a window milled in the existing intermediate casing. Two laterals were then drilled to different parts of the reservoir, and completed with cemented and perforated liners. Though most of the emphasis has been on the technology, the economic justification for multilateral wells lies in the additional production. Predicting production from multilateral wells is complicated, especially as, when these are in the same reservoir, production from one lateral will be reduced by production from the other(s). As for horizontal wells, production is best predicted via reservoir simulation, when data quality permits. Whereas a horizontal well typically costs 40% more than a vertical well and produces three times as much oil, a multilateral well might cost 60% more than a vertical well and produce five times as much. Obviously, the deeper the well, the more cost-efficient is it to drill the reservoir horizontally or multilaterally. Though readily available, multilateral well technology is still on a steep learning curve, so comparative costs will drop, especially for operators with limited multilateral experience. Multilateral wells are already enabling the development of fields which would otherwise be uneconomic, such as BPs Badami field in Alaska. 72 Revision 2: 2001 COMPLETIONS b) Applications Principal applications for multilateral wells include : • Improving the drainage architecture in a single reservoir, • Accessing discontinuous intervals/blocks in a single reservoir, • Draining more than one reservoir in a well, • Improving the efficiency of Enhanced Oil Recovery projects, • In combination with extended reach drilling, to develop fields from an offshore platform, or in environmentally sensitive areas, where the number and surface location of wells is severely restricted, and • As a means to re-use redundant wells, which have for example watered out, but which are near to undrained reserves. c) Technology The technology can be considered under three headings, Drilling, Completion and Intervention/Workover. The drilling technology is well developed, with systems offered by a number of service companies. In new wells, special windows can be installed with the main casing, to avoid having to mill windows. Special locator/orienting collars are installed below the windows, to allow the windows to be correctly oriented, using a survey tool, before the casing is cemented. A whipstock, run on drillpipe, is then set in the locator/orienting collar, across the window, to divert drilling tools out through the window. Once a lateral has been has drilled directionally, it may be left open, a slotted uncemented liner or sand control screen installed, or a liner cemented in place. With cased laterals, the liner stub, protruding into the main casing, must then be milled out, and the whipstock milled out or retrieved. In old wells, and with some systems in new wells also, pre-installed windows and locator/orienting collars are not used, and a special packer incorporating a locator/orienting assembly must be set in the main casing, after orientation with a survey tool, and a window milled, before the lateral can be drilled. If desired, the whole procedure can then be repeated to drill further laterals out of the same main casing. Most multilateral wells have then been equipped with conventional completions, with the packer, if used, above the upper lateral. However, this currently provides no possibility for re-entering laterals through the completion, and only very limited options even if the completion is pulled. Selective access to laterals, via coiled tubing, would increase the value of multilateral wells, by making possible selective stimulation, perforation, production logging, drilling deeper with coiled tubing and plugging of water-producing intervals. The paucity of intervention options may in the past have limited the spread of multilateral technology in situations where expensive wells, incorporating cased and cemented high angle or horizontal laterals, would be appropriate. Some two Revision 2: 2001 73 WELL PRODUCTIVITY AWARENESS SCHOOL DRAINING A SINGLE RESERVOIR MORE EFFICIENTLY UP-DIP AND DOWN-DIP LATERALS Drilling multiple laterals in a single reservoir greatly increases formation exposure and allows drainage over a larger area compared to a single lateral. In fractured reservoirs, additional laterals increase the probability of intercepting and draining different fracture systems. The number and geometry of laterals depends on the shape and characteristics of the reservoir. In the above example from the North Sea, a triple lateral well was drilled as a series of open hole sidetracks. The first lateral was turned to the right, the second lateral was sidetracked from the first lateral to the left, and the third or ‘main’ lateral was sidetracked from the second lateral and drilled straight ahead. Initial figures indicated a productivity of 2 to 3 times that of a conventional horizontal well in the same field. Odd-shaped leases or restrictions on surface locations can make drilling multiple laterals a preferred option. In South Texas, dual laterals drilled up-dip and down-dip are the most economic and efficient way of draining some leases. The vertical portion of the well is drilled to the top of the target, a fractured chalk reservoir, and casing is set. The up-dip lateral is drilled first at an angle above 90° to follow the formation dip. Next, the down-dip lateral is started as an open hole sidetrack and drilled to TD using the same bottom hole assembly used to drill the up-dip lateral. Multiple laterals can also be drilled as re-entries out of existing straight hole procedures, typically through a window milled in casing. The window is oriented halfway between the planned directions of the laterals. THE LATERAL TIE-BACK SYSTEM DRAINING MULTIPLE RESERVOIRS The Lateral Tie-Back System was recently used in Canada to complete a well drilled with three lateral branches extending from a main wellbore. The main horizontal wellbore was drilled with an 83/4" bit, and cased using a 7" slotted liner with three LTBS casing window systems installed 300 m apart. The windows were oriented in the same direction. The first lateral "branch" was completed open hole, with a slotted enclosure isolating the lateral. The second and third laterals were drilled and completed with 3 1/2" slotted liners hung from the 7" liner. Including the main wellbore, 2,850 m of reservoir was exposed. The total time from drilling to completion was just over 11 days. Multiple reservoirs can be produced using the same vertical well with stacked laterals drilled into the different producing horizons. Depending on completion requirements, the laterals can be drilled in open hole as sidetracks, through windows milled in casing, or through the LTBS windows. In the example above, the laterals below the casing shoe are drilled first as a series of open hole sidetracks using the same steerable assembly. The top lateral is drilled first followed by successively deeper laterals. If laterals higher in the well are desired, a retrievable casing whipstock is set at the desired KOP and a window milled. The lateral is then drilled before resetting the whipstock at the next KOP. Up to five laterals in three formations have been drilled in South Texas. Sperry-Sun Drilling Services 74 Revision 2: 2001 COMPLETIONS dozen wells are now completed to allow such selective re-entry via the completion. Of these, more than half use PCE’s Multi-Lateral Re-Entry (‘MLR’) system, the first of which was installed for NAM, in the Netherlands, in 1996. This system employs an oriented MLR nipple, set across the window before running the completion. A through-tubing whipstock may then be set in the MLR nipple, on coiled tubing, to deflect subsequent coiled tubing runs into the lateral. Offshore Qatar, where a number of these systems have been installed in the Idd El Shargi field, laterals have been selectively re-entered for acidising and production logging, for example. Most multilateral completions do not allow more than one tubing string to be installed, making it necessary to commingle production from the different laterals. Though this does not usually give rise to problems, it could lead to a well being killed by high water production from one lateral only, and might not permit production from intervals with different reservoir pressures. However, service companies are now offering multi-string completion systems, which permit segregated production from two laterals, with dual tubing strings to surface. The first completion of this type was installed by Baker Hughes in the Bokor field, offshore Malaysia in 1996, in a well with three laterals, each of which was completed with a sand control screen. Dual tubing strings to surface permit the segregated production of two laterals, with the option of adding production from the third to one of the others, by manipulation of a sliding sleeve. This completion also provides full hydraulic seals across the junctions where the laterals meet the main well bore, as all junctions are straddled with packers. Though workover options have been very limited in the past, MLR, and competing technology from other suppliers, makes possible a wide variety of through-tubing intervention options. When a rig workover is required, the MLR nipple can be retrieved on drill-pipe and a whipstock run in the locator/orienting collar, to allow access with drill-string into a lateral, thus providing a full range of workover options. Coiled tubing drilling, together with a number of other recently developed technologies, including under-balanced drilling, Logging While Drilling (‘LWD’) and geosteering are being combined to widen the range of options available for drilling multilateral wells. For example, the first under-balanced, multilateral horizontal well was drilled on coiled tubing onshore UK in 1995, with two uncased small bore laterals. In Oman, PDO are drilling a large number of innovative multilateral wells on coiled tubing, including some that will be drilled from old wells, via the 3” completion tubing, with a 2 3/8” hole size through the reservoir. Now that the challenges of drilling and completing multilateral wells have been largely solved by the service companies, oil company engineers are only just starting to identify novel applications, some of which may become commonplace in the future. Revision 2: 2001 75 WELL PRODUCTIVITY AWARENESS SCHOOL Geosteering Horizontal wells are becoming almost commonplace. The recent advances in drilling such wells is now focussed upon the accuracy to which they are being drilled. If a horizontal well cuts through the most permeable layers, or through the most fractured zones then well productivity can be significantly enhanced. Geological steering, or geosteering, is a development in this field. This technique uses real-time geologic data to guide the drilling of a well, and is aided by the use of today’s integrated computing displays. The engineer is able to display logs of previous wells on the screen, alongside the readings coming from the MWD-GR/Resistivity tools and is able to steer the bit exactly to the level of the formation he wishes. This technique could be used, for instance, to steer through a narrow known permeable band in a sandstone. Geosteering is also used to ensure that the bit does not drill completely out of the reservoir. The primary geosteering log is the resistivity log because of its deep depth of investigation. As the tool approaches a bed boundary with a significant resistivity contrast, a characteristic ‘horn’ will appear. At a 1° angle of attack the resistivity tool will detect a bed boundary 44 m before the tool crosses the bed boundary. Even with the MWD above the mud motor, the bed boundary can be detected before the bit drills the new formation. None of the other sensors are as effective for geosteering. Obtaining the logging information as close to the bit as possible will improve trajectory control. Geosteering can be enhanced by preparing ‘model logs’ for the well profile prior to drilling the well. The expected log response is modelled for the planned well profile using offset logging information. The actual is compared with the model during drilling to aid 76 Revision 2: 2001 COMPLETIONS interpretation. The preparation of the model logs can be time consuming, so it is important to plan ahead if these logs are to be used. Anadrill Schlumberger have refined their MWD/LWD tools to produce the Integrated Drilling Evaluation and Logging (IDEAL) system. Previously, directional drilling manipulation has been based on measurements some 50 ft to 100 ft behind the bit, depending on the BHA. Now, data measured near the bit are transmitted by wireless electromagnetic telemetry to an MWD tool, which pulses information through the mud column to the surface. This allows accurate near bit readings, yet gives the directional driller some flexibility with his BHA. 50 45 Trajectory 40 Apparent formation dip 35 30 25 20 15 10 5 0 10000 10500 11000 11500 Horizontal displacement Petroleum Engineer International UNION PACIFIC RESOURCES CORP. USED MWD GAMMA RAY DATA TO GEOSTEER THIS HORIZONTAL WELL. AN IMPORTANT CORRECTION CAN BE SEEN AT 10,930 FT. A different geosteering technique was used in BP’s extended reach wells (ERD) in Wytch Farm. A Reservoir Quality Prediction team was set up, including a geologist and a petrophysicist. They developed a model which quantified the permeability of the rock as drilling proceeded. The model was set up on an Excel spreadsheet. To work the system the drill cuttings were analysed to a greater degree than normal; including sieve analysis. Naturally, the model included a large amount of information gleaned from core data from surrounding wells. The well was steered through the most permeable part of the formation. The team believe that geosteering contributed greatly to the productivity success of the first Extended Reach Drilling (ERD) well at Wytch Farm. The model is now being further refined as the ERD campaign continues. Completion Design There are many types of basic completion available; this choice must be made before the details of tubing accessories, artificial lift etc. are contemplated. Each completion satisfies different needs. The engineer should investigate all the options before making his or her choice. Think of the life of the well; not just the immediate future. The completion types listed below may or may not need sand control (see Section entitled “Sand Control”). Revision 2: 2001 77 WELL PRODUCTIVITY AWARENESS SCHOOL a) Open Hole (Barefoot) Completion The well is produced from an open hole completion. The tubing is set in the casing and the well put on production. In most cases the casing would be set just above the reservoir. Advantages: • Cheap and simple (especially for long intervals) • Radial flow into well through 360° • Good access to fractures Disadvantages: • Mud filter cake will reduce productivity unless it cleans up • Production has to pass through any damaged zone • No protection against wellbore collapse • No zonal isolation 1 Casing is set at top reservoir or there is a danger that formations above will impair the well through collapse or production of unwanted fluids. 2 Zonal isolation is not possible. If a particular zone needs to be shut off (due to gas breakthrough in oil reservoir?) or stimulated, then separation is not possible. 1 2 3 4 3 Hydrocarbons are produced directly into the wellbore, which must be sufficiently strong to withstand collapse. 4 Oil/gas must pass through the near-wellbore damage zone to reach the wellbore. Mud filter cake will impair production unless it is fully cleaned up. BAREFOOT COMPLETION Zonal isolation is important if there is a water contact in the well; or possibly a gas zone above the reservoir. It may also be important later if production pulls in gas or water (to an oil well) and remedial squeezes (or other water shut-off methods) are needed. The lack of zonal isolation makes selective stimulation difficult. Zonal separation may also be needed if different reservoirs, or zones within reservoirs, have different reservoir pressures or depletion rates. b) Uncemented Liner The next most simple completion is to run a slotted or pre-perforated liner. The top of the liner is hung off in the previous casing. In most cases the previous string of casing would be set just above the reservoir. The liner is left uncemented. Advantages: 78 • Relatively cheap - dependent on type of liner (especially for long intervals) • Slots/holes need only be opposite reservoir • Radial flow into well through 360° • Good access to fractures Revision 2: 2001 COMPLETIONS • Slot sizes may afford some degree of sand control • Tubing shoe can be placed closer to reservoir • Protection against hole collapse Disadvantages: • Mud filter cake will reduce productivity unless it fully cleans up • Production has to pass through any damaged zone • No zonal isolation ADVANTAGES • Relatively cheap • Radial flow through 360o • Slot sizes afford degree of sand control • Liner prevents hole collapse DISADVANTAGES • Mud filter cake must be removed • Production must pass through any damaged zone • Minimal zonal isolation PAY ZONE Open Hole Damaged Zone Schlumberger Oilfield Review UNCEMENTED LINER COMPLETION IN DEVIATED WELL In some uncemented liner completions a degree of zonal isolation can be achieved by setting external casing packers (ECP). c) Cased and Perforated The majority of wells around the world are completed in this fashion. Advantages: Revision 2: 2001 • No need to clean up filter cake • Perforations by-pass the damaged zone (if engineered correctly) • Good zonal isolation • Casing programme not compromised • Multiple/selective completions possible • Good well integrity - if properly cemented • Protection against hole collapse 79 WELL PRODUCTIVITY AWARENESS SCHOOL Disadvantages: • Possible skin due to lack of 360° coverage • Permeability impairment due to crushed zone and perforation debris • Expensive, especially over long intervals* *This is particularly important with long horizontal wells. The cost of perforating, say, a 5000 ft horizontal well with a 7” liner could be approximately £600,000: ADVANTAGES • Perforations pass through filter cake and any damaged zone • Zonal isolation possible Production casing • Multiple selective completions possible • Good well integrity Cement Cemented liner Damaged Zone DISADVANTAGES • Perforations may not bypass all of damage - or may cause own damage due to crushed zone/imperfect clean-up • Expensive, especially over long intervals Selective perforations CASED AND PERFORATED COMPLETION All the above completions may or may not fully penetrate the entire reservoir. Remember that the ideal radial flow equation was for a fully completed, vertical, open hole well drilled entirely through the reservoir; thus if a completion is only across half the reservoir (partial penetration or partial completion ) then there will be a positive skin. Completion Practices In the previous section we have already discussed types of completions, and why such completions are chosen. In this section we will discuss how to put those completions into the ground, and the important issues with reference to formation damage and well productivity. 80 Revision 2: 2001 COMPLETIONS Casing and Cement The most common completion is the cased and perforated variety, yet cementing of casing remains one of the least successful facets of the drilling/completion operation. There have been countless papers on primary cementing and all that can be done to improve it, yet cement jobs still fail and cement bonds are frequently poor. One of the advantages of the cased and perforated completion is the ease of zonal isolation; yet if the cement bond is poor, the effective zonal isolation will also be poor. Cement Casing Oil Perforation Good zonal seperation thanks to solid cement bond Mud (Channel in cement job) Poor cement job lends to lack of zonal isolation Oil Good cement job Hole size Perforations reach past the damaged zone Damaged zone Perforations fail to penetrate through the cement sheath and/or the drilling damage. HIGH SKIN Hole size Damaged zone Productive Well Poor cement job can decrease productivity CEMENTING Running and cementing casing usually takes a small amount of time, compared with the drilling operation. Consequently, although cement filtrate may be damaging to many reservoirs, there is little time for invasion to occur and hence the damage is shallow. The overall effect on productivity is small – perforations should easily go beyond any cement filtrate damage. It is however recommended that fluid loss of the cement be controlled, especially if the hole is overgauge. Squeeze cementing has a much greater potential to reduce well productivity compared to a casing or liner cementation. This is due to the perforations increasing the radius of the zone that is damaged. There is also a danger of cement filling up any cavities (due to sand production) behind the casing. Often, re-perforation (with smaller guns, and no drawdown) will not reach past such damage. Naturally fractured reservoirs are most likely to be adversely affected by cementing: if the most conductive fractures are filled with cement then the well may not flow. Stimulation treatments (with diversion) are usually required to regain communication with the fracture network, but sandstone is only slightly soluble in mud acid, so cemented fractures are very difficult to clean up or by-pass. Revision 2: 2001 81 WELL PRODUCTIVITY AWARENESS SCHOOL A POOR CEMENT JOB CAN DAMAGE WELL PRODUCTIVITY WE NEED TO ACHIEVE THE SITUATION ILLUSTRATED IN ‘D’ BELOW SCHLUMBERGER ULTRA-SONIC IMAGER (USI) TOOL 82 Schlumberger Oilfield Review Revision 2: 2001 COMPLETIONS If casing has already been perforated (as would be the case in a workover) then there is a danger of cement filling the perfs (and any cavities) and cement filtrate invading the formation to a greater depth than could be reached by any reperforation Beware of squeeze cementing forcing cement into natural fractures & thereby sealing them = Formation Damage Oil Oil Mud OWC Oil Water Contact Cement SQUEEZE CEMENTING Care should be taken not to fracture a reservoir by surging when running in hole with the casing. Not only will lost circulation compromise well safety, but the invading fluid (mud/mud filtrate) could cause formation damage. Use swab-surge computer programmes to prevent this. Completion Fluids A well completion will either attempt to perforate through any damaged zone, or a clean-up will attempt to remove the filter cake and some of the formation damage. In each case it is imperative that the fluid used for the completion is itself non-damaging. In the previous section it was stated that perforations should by-pass the bulk of the formation damage to reach virgin formation; however if the fluid in the hole at the time of perforating is itself damaging, then the exercise is merely creating another damage zone. The perforating issue will be dealt with in the next section: suffice to say here that the completion fluid must be filtered and nondamaging. (In some instances it is not necessary to filter completion fluids, but a safe practice is to filter any fluid during the completion phase that will contact the reservoir at any time.) The danger of surging the formation was mentioned above for running the casing; the same thing can happen when running the completion packer. In addition, poor design of the tensional and compressional forces during packer setting could induce fractures and losses. Revision 2: 2001 83 WELL PRODUCTIVITY AWARENESS SCHOOL a) Types Completion brines are filtered salt solutions – the salt that is used depends upon the density required and should also consider the potential for incompatibility with the reservoir. SG PPG (Fresh water = 1.00) (Fresh water = 8.3) Potassium Chloride (KCl) Sodium Chloride (NaCl) Sodium Bromide (NaBr) Calcium Chloride (CaCl2) Calcium Chloride/Bromide (CaCl2/CaBr2) Caesium Formate (CsCOOH) Zinc Bromide (ZnBr2) up to 1.16 up to 1.20 up to 1.50 1.20 - 1.35 1.25 - 1.70 1.70 - 2.36 1.70 - 2.30 up to 9.7 up to 10.0 up to 12.5 10.0 - 11.2 11.2 - 14.2 14.2 - 19.7 14.2 - 19.2 In most cases do not use seawater to mix completion brines – it is not suitable. For example, many formation waters precipitate inorganic sulphate scales when mixed with seawater. This scale can form in the pore spaces causing high skins, and may be impossible to remove. Note that brine density is sensitive to temperature. Thus when measuring the density, the temperature should also be considered. This is especially important when mixing some brines due to dramatic changes in temperature when dissolving some salts. For example the dissolution of calcium chloride is an exothermic reaction (the brine temperature can increase to 50°C) and with potassium chloride the reaction is endothermic (the brine temperature can often fall to below 5°C). With hot, deep wells the density of the brine at depth will be considerably different from the density at surface. Salts may crystallise out as temperature falls. Typical viscosifiers used in completion and workover fluids are organic polymers. They can sometimes be difficult to disperse, especially into high salinity brines. The pH of the fluid can also affect the ease of polymer dispersion. High shear mixing is required otherwise small lumps of undispersed polymer gel (‘fisheyes’) will remain. These ‘fisheyes’ may not degrade with time nor be destroyed by future acid treatments. To mix high salinity viscosified brine it can be beneficial to pre-hydrate the polymer in a lower salinity fluid first. b) Importance of Cleanliness/Filtering Filtered brines are used as completion fluids to: • • Ensure that minimal solids are present to settle on top of packers or in sliding sleeves and other downhole tools. Ensure that no solid particles block the perforation tunnels or the formation pores within the perforation tunnels Brines are often described as ‘solids free’; but this is a misleading statement, since the salts that are used to mix brine always contain some impurities (the best NaCl is PVD – pure vacuum dried), and they may get contaminated during transport or handling. QA/QC of the salt supplied could be critical. 84 Revision 2: 2001 COMPLETIONS Why Filter? Ensure no solids present to settle onto packers, and in accessories (e.g. sliding side doors) Ensure no solid particles present that may block pore spaces/throats in the perforations and/or the reservoir – Note that even fresh water and the best quality PVD NaCI MUST be filtered Solids invasion was discussed in Chapter 3. Drilling muds have a high solids content in the region of 10 - 20% v/v, whereas completion brines tend to contain less than 0.05% v/v. Consequently brines have no ability to form a filter cake, and significant quantities can be lost into the formation. In addition, the low solids concentration can allow what solids there are to invade further into the formation as bridging across pore throats is reduced. It is therefore important to control the size of solids in the brine by filtration; the smaller the solids, the less likely they are to plug pore throats. If completion fluid during or after perforation contains large solids they will plug the hitherto undamaged formation = Loss of Productivity Wellbore Contains Completion fluid Virgin reservoir No invasion from mud filtrate Casing Cement Damaged zone invaded by Mud filtrate PERFORATION DAMAGE But when we say a ‘clean brine’, what exactly do we mean? How much rig time are we going to spend circulating and filtering to achieve the clean brine? Limits must be set for any completion brine. Decisions must be made beforehand on whether a brine will be filtered to 10 micron, 5 micron or 2 micron (1 micron = one millionth of a metre). Note that particles smaller than 40 micron are invisible to the naked eye. This will depend upon the formation and the practicality of the particular situation. Decisions must be made in advance as to how ‘cleanliness’ will be measured: turbidity meters, Coulter Counters, Malvern metres, etc. ‘Eyeballing’ a visually clean brine is no longer good enough. This operation can take a long, long time (24-48 hours). The time is usually well spent and worthwhile. Revision 2: 2001 85 WELL PRODUCTIVITY AWARENESS SCHOOL Filtering Cartridge Nominal Diatomaceous Earth (DE) Absolute Nominal If losses into a formation render a well unsafe or filters cannot keep up with the loss rate, the well must be stabilised with a kill pill. The formulation of kill pills in the completion phase is significantly different from those used in the drilling phase. This subject is covered in the section on workovers in Section 7. Two main types of filtration are used: Cartridge : Nominal Rating – refers to the typical size of the particle that is removed, but some larger particles get through the filter. Absolute Rating – actual size of the holes in the filter itself. A 10µ absolute may equate to a 2-3µ nominal filter. Diatomaceous Earth: diatomaceous earth builds up a permeable filter cake that traps any unwanted solids. DE filters are nominal filters and usually have an absolute ('polishing') cartridge filter downstream. DE filters can handle much dirtier brine than cartridge filters. They are not good at handling oily water. All tanks and pipework must be cleaned beforehand All contaminants MUST be removed: rust, scale, coconut figures from nuts, pipe dope, tubing dope, old mud etc. must be eliminated. NEW BRINE MIXED WITH FRESH WATER AND CLEAN CONSTITUENTS (SALT) If dirty fluid is dumped (where/when regulations allow) BAG FILTER (OPTIONAL) DIATOMACEOUS EARTH FILTER If reasonably clean then returning fluid is re-filtered Check differential pressure across cartridge to ensure optimum operation Measure cleanliness Inspect D.E. bed frequently Do not allow loose diatomaceous earth to go into the completion fluid. It will plug formations! CARTRIDGE FILTER(S) (sometimes called 'polishing' filters) Measure cleanliness Downhole tubulars must be scrupulously clean DOWNHOLE RETURNS FROM THE WELL TYPICAL FILTER SET-UP 86 Revision 2: 2001 COMPLETIONS Whatever the type of filter, filtration is not a ‘start-it-up-and-let-it-run’ operation; the system must be constantly monitored and maintained. c) Displacement There is no point in placing ‘absolutely’ clean brine into a dirty well and ending up with it mixed with dirty mud. Displacing solids-laden mud with clean brine is not straight forward. In order to minimise contamination of the brine, the method of displacement is important. Depending upon the criteria set (for example, in gravel packed completions the cleanliness criteria are even more severe than in normal cased and perforated completions) there will be a series of circulations necessary to clean up the system prior to displacing the well to completion brine. Note that the word ‘system’ is used, since the tanks, pumps, lines, drill pipe/tubing, and the casing walls will all have to be free of solids prior to the brine going into the hole. If surfactants are used to clean up the tubulars, it is imperative that they be circulated out as they may cause formation damage themselves by the methods already mentioned earlier. If a well is not going to be perforated, it is essential that the mud filter cake be removed from the wellbore when the well being completed. This problem – especially in horizontal wells – is the subject of ongoing research. In such a case the mud solids are usually chosen to be soluble (calcium carbonate in acid, sized salt in dilute brine, oil-soluble resin in oil etc). Perforating Charlie Cosad of Schlumberger wrote “The fate of a well hinges on years of exploration, months of well planning, and weeks of drilling But ultimately it depends on performing the optimal completion, which begins with the millisecond of perforation. Profitability is strongly influenced by this critical link between the reservoir and the wellbore”. There are three basic types of perforated completion, each with its own specific requirements. Completion Type Perforation Natural: Stimulated: Gravel Packed: If perforation is to be immediately followed by production, then many deep shots would be most effective. In stimulated completions – hydraulic fracturing and matrix acidisation – a small angle between shots helps to effectively create hydraulic fractures and link perforations with the new pathways in the reservoir. Many large diameter perforations filled with gravel are used to keep unconsolidated formation from producing sand. Perforating is extremely important. All perforations must be meticulously planned – any old holes will just not do. The purpose of the perforation is to by-pass the damage zone and reach virgin reservoir. Revision 2: 2001 87 WELL PRODUCTIVITY AWARENESS SCHOOL a) History of Perforating With the advent of cased completions came the need to perforate wells. Early wells were merely connected to the formation via a slot made by a mechanical perforator where a blade was forced through the casing. These were not very effective. The first wireline-conveyed bullet perforators were used in 1932 and gave much better results. Shaped charge perforators, which came from the development of armour-piercing weaponry in World War II, were introduced shortly after that conflict, and gave even better results. This form of perforating, run on electric line, dominated the market until the introduction of Tubing Conveyed Perforating (TCP) guns by Vann Systems in the early 70’s. b) Perforating Charges A shaped charge is a precisely engineered cone of pressed metal powder, or drawn solid metal, surrounded by a secondary explosive and case, and initiated by detonating cord. Detonation collapses the cone into a jet which generates millions of psi pressure at huge velocities and penetrates the casing and the formation. Explosive Primer Well casing Cement Detonating cord 0 µ sec Damaged zone Case Liner Formation 4 µ sec 9.4 µ sec Progression of shaped-charge detonation. The schematic at 0 µsec shows the charge components. The volume of explosive is greatest at the apex of the liner and least near its open end. This means that as the detonation front advances, it activates less explosive, resulting in a lower collapse speed near the liner base. The subsequent drawings show the case deforming as the detonation front advances, thrusting the liner into a jet along the shaped-charge axis. The fully formed jet, at 16.6 µsec, is moving at about 21,300 feet/sec (6500 m/sec). Crushed rock 16.6 µ sec Perforation tunnel 6-16" The perforation can contain crushed rock and liner debris The metal case creates debris that can cause mechanical problems within the wellbore PERFORATING CHARGES THE SHAPED CHARGE 88 Revision 2: 2001 COMPLETIONS The detonating cord or 'primacord' is a continuous connection down the length of the gun. Boosters are sometimes employed to pass the detonation along to another gun (below/above). The detonating cord is activated by the detonator , which is set off by electrical impulse, mechanical impact or pressure. The detonating cord in turn sets off the p r i m e r , which is a small amount of higher sensitivity secondary explosive at the base of each shaped charge. This ensures correct initiation of the explosion. Various grades of e x p l o s i v e a re used; dependent upon the downhole temperature, and the time that the guns will be in the hole before they are fired. For instance, a TCP gun will be exposed to wellbore temperatures for a greater time than wireline conveyed guns, so RDX may be suitable for the wireline gun where HMX (higher temperature rating – more expensive) will have to be used for the TCP guns. The amount of explosive per shaped charge varies from 3 to 66 grams: the greater the charge, the greater the penetration. However, the larger the charge, the less charges per foot that can be run. The casing and the shaped charge is disintegrated into fingernail-sized flakes of debris, and this debris can be a problem. It may plug the perforations. The various suppliers have developed low debris charges. ‘Low debris’ actually means different debris: fine powder rather than metallic flakes. Low debris charges can be useful in horizontal wells where it can be produced out of the well; whilst it may be difficult to move the larger flakes from the conventional charges. ‘Big Hole’ charges have been developed for gravel-packing applications. They have a liner made from a solid copper sheet to help create a big diameter hole (1.0” vs. 0.4”). Unfortunately, the sheet liner forms a slow moving ‘carrot’ behind the jet, which can block the perforation tunnel. ‘Deep penetrating’ charges are used for consolidated sandstones, to get the best production rates. Powdered metal liner 0.4" Depth of damage (~12") ‘Soft’ or poorly consolidated sandstones which need to be gravel packed are perforated with ‘big hole’ charges. Solid liner This perforation is packed with gravel to prevent sand production. 1" Casing Cement PERFORATING HARD OR ‘SOFT’ SANDSTONES Revision 2: 2001 89 WELL PRODUCTIVITY AWARENESS SCHOOL c) Delivery Systems There are essentially two ways of getting a gun down the well: on wireline (with through-tubing and casing guns) and on tubing (Tubing-Conveyed Perforating – TCP). Through-casing perforation (Generally overbalanced) Through-tubing perforation (Generally underbalanced) Tubing-conveyed perforation (Generally underbalanced) Workstring Casing Tubing Packer Packer Firing head Casing gun Through -tubing gun Safety spacer Flow entry ports Guns Three conveyance methods for perforating guns: through-casing and through-tubing, and tubing-conveyed systems. The through-tubing gun shown is held against the casing magnetically. The others hang free. GUN DELIVERY SYSTEMS Schlumberger Oilfield Review Wireline conveyed casing guns are not usually fired underbalanced; whereas the through-tubing and TCP guns can use this method of enhanced perforation cleanup (more of which later). There are two broad categories of gun type: exposed and hollow carrier. Exposed guns are run on wireline and have individual shaped charges sealed in capsules and mounted on a metal strip or bar. The detonator and detonating cord are exposed to borehole fluids. These guns are used exclusively throughtubing and leave debris after firing. They include two designs: ‘expendable’ (charges and mounting assembly become debris) and ‘semi-expendable’ (mounting only is recovered). For a given diameter, exposed guns carry a larger, deeper penetrating charge than a hollow carrier gun. These guns usually come with zero-degree phasing; therefore a bow-spring or magnet should be used to press the charges against the casing. The length of gun that can be run depends upon the length of lubricator that can be rigged up. These guns are frequently run through-tubing for reperforating where pulling the tubing would not be economic. Hollow Carrier guns become preferable to exposed guns above about 21/8”, because above this size, the casing, or hollow carrier design, becomes more practical, allowing the use of larger charges, optimal angle between shots – called ‘phasing’ (at 0, 45, 60, 90, 120 degrees) – and increased number of shots per foot (4, 6, 8, or 12 spf) – called shot density. 90 Revision 2: 2001 COMPLETIONS Gun System Exposed gun Application Wireline through-tubing Strip X Pivot X Scallop X Wireline through-casing X Port plug Hollow carrier gun Tubing conveyed High efficiency X X High shot density X X X Schlumberger Schlumberger nomenclature Nomenclature Types of perforating guns and their application Hollow carrier guns have shaped charges positioned inside a pressure tight steel tube. The design is available for most tubing and casing sizes. It is used through tubing when debris is unacceptable or in hostile conditions that preclude exposed guns. The main types of hollow carrier guns are: • Scallop guns: so-called because charges shoot through dished out areas in the carrier (to reduce burr protrusion). • Port Plug guns, in which charges shoot through replaceable plugs in a reusable carrier. These are wireline conveyed, mainly for deep penetration, and where 4 shots per foot is acceptable. The wireline conveyed guns can be pulled out of the hole immediately after the guns have fired. The TCP guns have to remain in the hole until the tubing string has been pulled. Alternatively the TCP guns can be released (usually by slickline manipulation) and dropped down the hole. If this is done, an additional sump has to be drilled to make space for the guns. If the sump can not be provided, the well will have to be ‘killed’ after the underbalanced perforating, and the guns withdrawn from the well before the completion is run. This opens up the potential for damage to the formation from the completion fluid leaking off into the new perforations. To prevent this happening an oil-soluble resin, calcium carbonate or sized salt LCM can be put across the perforations to stop the fluid loss whilst the guns are retrieved. TCP guns are usually more expensive to run because of all the rig time consumed. However, for very long intervals they may take less rig time than wireline conveyed guns – since a large number of perforating runs (dictated by the length of lubricator) will have to be made. Note that even with the well flowing during perforating it may not be possible to achieve the same drawdown as the first perforating run. Also, care has to be taken not to blow a wirelineconveyed gun up the hole causing a 'birdsnest' and a subsequent fishing job. d) Perforation Skin The near wellbore region plays a vital part in the productivity of every well. All the fluid produced from the reservoir has to pass through this region. Revision 2: 2001 91 WELL PRODUCTIVITY AWARENESS SCHOOL Damaged zone Perforation diameter Perforation varies with shot density Phase angle Crushed zone Perforation penetration Schlumberger Oilfield Review Major geometrical parameters that determine flow efficiency in a perforated completion. Four key factors are shot density, phase angle, perforation penetration into the formation and perforation diameter. Productivity of a well also depends on the size of the crushed zone, whether the perforation extends beyond the damaged zone and how effectively the crushed zone and charge debris are removed from the tunnel. Phasing from top 6 3 8 0 45° 1 5 135° 4 7 2 0° phased Enerjet 45 90 135 180 225 270 315 360 8 1 2 4 3 7 1 1 Gun in casing Schlumberger Oilfield Review 3 6 5 7 2 60° phased scallop gun A family of through-tubing, wireline-conveyed guns. From left, the 0° phased Enerjet (a semiexpendable strip gun), the phased Enerjet, with two rows of charges at 90° (an expendable strip gun) and the 60° phased scallop gun (a retrievable gun). Unlike the Enerjet, the scallop gun has negligible debris and can be run in hosite environments. 8 2 4 6 6 5 6 ±45° phased Enerjet 8 Casing unrolled (7 in.) Three views of perforating with a 135°/45° phased gun: the gun fired in casing, phasing viewed from the top, and with the perforated casing unrolled and laid flat. The 135°/45° designation means the angle between successive shots is 135°, resulting in an overall phasing of 45°. There is 1 vertical inch [2.5 cm] between shots, making 12 shots per foot. In the natural completion, this phasing provides hydrocarbons with the most direct path to the wellbore. GEOMETRIC FACTORS THAT DETERMINE FLOW EFFICIENCY 92 Revision 2: 2001 COMPLETIONS Even in the absence of a damaged zone it is possible to create a mechanical skin by imprudent choice of perforating gun. A zero skin is where there is the same pressure drop as ideal undamaged radial flow into the open hole, uncased well. A mechanical skin will exist where there are any features around the well that increase the radial flow pressure drop. For example, zero phased perforations with 3” tunnel length, fired at 4spf, causes a skin of +5, even if there is no damaged zone. When formation damage is present, the skin will be many times larger. Hydrocarbons have a more tortuous path to reach the wellbore. This is contrary to the idea of 360° radial flow thus there is a ‘mechanical skin’ Zero phased perforations MECHANICAL SKIN CAUSED BY ZERO DEGREE PHASING The science of predicting the near wellbore skin has passed from empirical models to computer simulation. The work of Karakas and Tariq (SPE18247) is widely accepted as the best guideline, giving equations to predict mechanical skin using a specified amount of drilling damage, perforation details (phasing, spf, penetration, crushed zone damage), and formation anisotropy. If a small diameter gun is run in a larger casing there is a danger of the situation below developing. Where possible the largest OD casing gun or TCP should be run - but remember that you must be able to fish the gun should it get stuck. Debris if insufficient underbalance Ineffective to clean it out perforation If guns are not centralised some perforations will be well below specification To make this field Gun willviable lie on low economically this rate must side ofbethe hole achieved until the end of year seven. Perforation casing diameter about 0.4" Crushed zone Tunnel length up to 20" GUN IN CONVENTIONAL (~20° DEVIATED WELL) Revision 2: 2001 93 WELL PRODUCTIVITY AWARENESS SCHOOL e) Perforating Through Drilling Damage It is vitally important to perforate through any drilling damage. Shot density is important, since more holes means more places for hydrocarbons to enter the wellbore and the greater likelihood that perforations will intersect productive intervals in a variable (anisotropic) reservoir. Under typical flow conditions, perforation tunnel diameter does not adversely affect flow, provided it exceeds 0.25” (6mm); which today is provided by almost all guns. 1.4 1.2 1.0 0.8 In this well, if the perforation length exceeds 12" then the virgin reservoir is tapped and the productivity of the well is restored. The greater the shot density the better the productivity, 0.6 0.4 0.2 Damage Depth - 12" Kd/K - 0.1 0.0 0.0 4.0 8.0 12.0 16.0 20.0 Perforation Length (in) PERFORATING THROUGH DRILLING DAMAGE f) Perforation Tunnel Length The actual perforation tunnel length has a significant impact on well performance. The data to estimate perforation tunnel length is given by the manufacturers in accordance with the API Recommended Practice 43. Edition 5 of RP43 was published in Jan.1991. Section 1: A multi-shot test into a block of concrete at ambient conditions Section 2: Single shaped charge fired into a 39/16” cylinder of Berea Sandstone at 3000 psi confining stress. Note: Many companies will publish the results of the less stringent Edition 4 tests. Beware: The API RP43 results at best gives a relative measure of downhole perforation lengths. In 1984 Exxon performed a ‘shoot-out’ between all the manufacturers, under controlled conditions, and found that none of the results met or exceeded those stated by the manufacturers. The penetration results of Section 1 tests (in concrete) real perforations, as ‘target activity’ will always reduce the concrete figures. As a rule-of-thumb, Section 1 results should be reduced by 33% to be equivalent Section 2 (in Berea Sst) test. 94 Revision 2: 2001 COMPLETIONS Percentage of reported API penetration 0 50 100 Dresser Atlas Gearhart Schlumberger* Harrison SCS SIE Geoscience GOEX Owen JRC *Schlumberger acheived the longest perforations in each class EXXON SHOOT-OUT, 1984 New Deep Penetrating Charges Schlumberger have recently introduced new perforating charges which by virtue of their improved charge liner and denser explosive packing technology offer a significant improvement (38%-54%) in target penetration. The table below compares the new 51J HMX and 37J HMX charges with existing options. Both the 51J and 37J charge types have been field tested by several operators worldwide. The HMX temperature rating allows the guns to be considered in most BP reservoir environments. Charge Name Charge API Carrier Density Phasing API Size Section 1 Section 1 Size (grammes) (ins) (shots/ft) (degrees) Penetration Entry Hole (ins) (ins) 51J Ultrajet HMX 51B Hyperjet II HMX 51B Hyperjet II RDX 38.5 37 37 41/2 41/2 41/2 5 5 5 72 60 60 43* 31.05 30.52 0.45* 0.45 0.48 37J Ultrajet HMX 41B Hyperjet II HMX 41B Hyperjet II RDX 34 22 22 31/2 33/8 33/8 4 6 6 60 60 60 34 23.5 22.12 0.46 0.4 0.36 *Unofficial API Data The principal applications of these charges include: • Zones with formation damage which extends beyond the penetration depth of existing charges (e.g. Cusiana). • Zones which have been remedial cement squeezed resulting in a large annulus of cement around the wellbore due to previous formation production (e.g. Forties). Revision 2: 2001 95 WELL PRODUCTIVITY AWARENESS SCHOOL Always check the conditions under which the results were obtained. There are corrections that must be made to the API Section 2 results, when deciding upon which charges to use to perforate an actual well. There are corrections for: 1. Unconfined Compressive Str ength – the rock you are actually perforating may be harder or softer than Berea. North Sea rock is usually softer than Berea. 2. Confining Stress – the Edition 4 tests are done at 1000 psi confining stress. The Edition 5 tests are done at 3000 psi confining stress, which can reduce the performance of a charge by 10%. Above 3000 psi there is not much difference. Check to see which Edition the perforating company is quoting. 3. Clearance – there is of course a difference between having the charge pressed against the casing, versus an offset. Check what the perforating company is quoting vs. how you are perforating. Guns are tested according to API 43. Section 1 is a multi-shot test into a concrete target. Section 2 is a single shot into a cylindrical Berea sandstone core more representative of real formations. Berea TTP Sealing material Steel Perforation If no Berea tests were done, use 66% of the concrete test perf. length to estimate Berea perf. length. Typical Perforation Lengths Charge size 6.5g 22g Section 2 Test TCP High permeability beads or rods Soft formation Hard formation 10" 3" 17" 7" To convert Berea perforation lengths to actual downhole penetration the lengths must be corrected for formation compressive strength, overburden stress and clearance. Perforations go further in weaker rocks with less overburden stress. These corrections are important: for instance the Total Target Penetration can be halved if penetrating a much harder rock than Berea. If you have computer programmes to help you (BP’s KTPerf and Inflo2), use these to assist you in your decision; if not, press the perforating company for more and better information. Quality control of perforators is important: • • • • How old are the charges? How have they been stored (temperature/stability)? How have they been transported? Who manufactured them and where? g) Underbalanced Perforating Crushed Zone Immediately around each perforation tunnel is a ‘crushed zone’, where the formation has been deformed. The thickness and permeablility of the crushed zone depends upon charge size, rock type and underbalance. It is usually about 96 Revision 2: 2001 COMPLETIONS Thin Section of Undamaged Rock Thin Section of Crushed Zone (50% less permeability) DAMAGE AROUND THE PERFORATION Blue = Porosity/Permeability 1/2” thick, and has about 50% of the undamaged formation productivity. CAT scans and thin sections have shown that porosity is maintained in the crushed zone. The larger pores are destroyed, and the grains become micro-fractured. If this crushed zone is not removed, the productivity from each perforation will be impaired. Overbalanced perforating before flowing Damaged zone Virgin formation Change debris Cement Casing Without cleanup, the perforation tunnel is plugged by crushed rock and charge debris. Crushed (low-permeability) zone still exists Overbalanced perforating after flowing Part of low-permeability zone still exists Perforation partially plugged with charge debris Flow has removed most charge debris, but some of the low-permeability crushed zone created by the jet remains. Ideal underbalanced perforating Crushed zone and charge debris expelled by surge immediately after perforating Sufficient underbalance during perforating removed damage - both charge debris and crushed rock. Schlumberger Oilfield Review This one will have by far and away the best productivity. Revision 2: 2001 97 WELL PRODUCTIVITY AWARENESS SCHOOL Schlumberger Oilfield Review 98 Revision 2: 2001 COMPLETIONS Underbalance One important parameter that the engineer has control over, and that can influence near-wellbore skin, is the amount of underbalance. Underbalanced means that the wellbore pressure is less than the formation pressure before perforating; thus there is a flow into the wellbore immediately after perforating. Underbalanced perforating gives better well productivities; the strong surge of flow out of the perforations removes crushed rock and fine debris, giving clean, open perforations. Once the debris is out of the perforations it must be produced out of the well. Wireline perforating can only be slightly underbalanced. The first run in the hole might be a few hundred psi underbalance; perhaps more in low productivity wells. If the underbalance is too great there is the real danger of the guns getting ‘blown up the hole’ with dire consequences. In contrast, tubing conveyed perforating allows much larger, safe underbalances. Clean perforations are thought to be obtained by a sufficient flowrate out of each perforation. Hence a lower permeability reservoir will require a larger underbalance. King (1986) produced a graph, of minimum underbalance vs. permeability. If weak formations are perforated with too high an underbalance, there is a danger of the perforation tunnel collapsing - leading to impaired well productivity. 1000.0 100.0 These wells flowed as per expectation. 10.0 1.0 0.1 100 Inadequate underbalance Adequate underbalance 1000 Underbalance (psi) These wells recorded a positive skin. 10000 EFFECT OF PERMEABILITY ON REQUIRED UNDERBALANCE In the Cusiana field for instance, an early well was perforated with an underbalance of 2000-3000 psi and this resulted in much lower skins than seen in a later well where the underbalance was only 500-1500 psi. Revision 2: 2001 99 WELL PRODUCTIVITY AWARENESS SCHOOL Too much underbalance can also cause problems; for example the collapse of perforation tunnels leading to sand production in weak formations. This was thought to be the problem in Cusiana which is why the underbalance was reduced. (In fact the debris turned out to be crushed rock from the perforations and they were able to revert to the higher underbalances.) It might also create a fines migration problem in some formations. It might also unseat the TCP packer or collapse the tubing. The level of underbalance is controlled by using a cushion of nitrogen, diesel or brine. ‘Backsurging’ may be used to clean out perforation tunnels if underbalance is not possible, or insufficient, at the time of perforation. Backsurging is done with special tools run in completion or workover strings. BP Alaska use instantaneous underbalance devices (IUD’s) following reperforating with wireline conveyed guns. A similar underbalance device has been used on Ula and Gyda. These tools are however limited by the length of formation they affect by each application (approx. 50 ft). The clean-up of perforations by backsurging after the well has been put on production is thought to be less effective when compared with underbalanced perforating. This is because the hydrocarbons by this time have found the paths of least resistance through the damage and this route will never be as good as through the entire fabric of the rock. Perforation Plugging A cased and perforated well relies on its perforation tunnels as the avenues of production. These tunnels can very easily become plugged. This emphasises the need to perforate in clean completion fluid, and to keep the wellbore free of plugging materials such as pipe dope. Pipe dope will block perforations and is difficult to remove. Therefore be sparing with the application of dope to tubing, and apply with a small paintbrush to pin ends only. This is a example where anyone and everyone can influence the productivity of the well. It is possible for just one slug of dirty fluid going downhole to completely plug all the perforations – PERMANENTLY. A perforation that is 16” long and 0.4” in diameter only has a volume of 2 cubic inches or 32 cubic centimeters. Imagine how easy it would be to plug off the perforation entirely; or even just plug off the perforation entrance with a globule of tubing dope! Paint from completion equipment can also come off downhole, and enter the perforation tunnels. This is why brightly painted packers – be they yellow, blue or red – are stripped of their coats of many colours before being run in the hole! Always be careful when tripping into the hole with open perforations – especially with a packer in the string. A strong surge could cause formation breakdown, losses and damage. h) Overbalanced Perforating In the section above the necessity and benefit of underbalanced perforating was explained. Nowadays the vast majority of wells are perforated underbalanced. 100 Revision 2: 2001 COMPLETIONS However, Oryx Energy (U.S.A.) became worried by some of the poor results that they were getting from their perforated completions. They calculated that they were only achieving an average of 25% completion efficiency: only one perforation in four was effectively contributing to production. Oryx therefore investigated ways to improve this; both within the techniques already employed and by experimenting with new techniques. Some observers (including BP Sunbury) had noted that there were a series of radial fractures around perforation tunnels. Oryx reasoned that if a well was perforated in severe overbalance , that these fractures might be extended and actually enhance the productivity of the perforation. Thus overbalanced perforating was born. Oryx have achieved some measure of success over more than 50 wells, and are now licensing the technique via the relevant service companies. Halliburton have such a license and are actively marketing the new technique. Closure of Fractured Perforation Overburden causes perforation tunnel to close up? A simplified look at a perforation The smaller than expected perforation tunnel will lead to lower productivity Outer bounds of perforation tunnel Fractures created by perforation jet Fractures initiating from applied overbalanced pressure σ max (maximum horizontal stress) σ max Revision 2: 2001 Perforations here are extending past the explosive tip of the perforation. This leads to enhanced productivity 101 WELL PRODUCTIVITY AWARENESS SCHOOL The table below illustrates the negative skins that can be achieved. Build-up results for overbalanced well treatments Well/state location O.B. Type Formation fluid name/type system Midperf BHP O.B. (perf/ depth. Perf. Resv. surge) ft ft psi grad. psi/ft K Skin 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. Strawn SS Strawn SS Strawn SS Strawn SS Strawn SS Atoka SS 1st Spiro Morrow SS Atoka SS Strawn SS Morrow SS Svn Rvrs SS PDC SS Red Fork SS Strawn SS Skinner SS Perf Perf Perf Perf Perf Perf Perf Perf Perf Perf Perf Surge Perf Surge Surge Surge 1.39 1.39 1.39 1.39 1.40 0.87 1.25 1.21 1.10 1.27 1.11 1.69 1.33 1.18 1.06 1.24 -0.6 -2.2 -2.3 -2.3 -2.0 -2.3 -1.4 85 -3.3 -3.6 -5.0 10.0 -0.4 -1.5 -1.1 -1.5 Texas Texas Texas Texas Texas New Mexico Oklahoma New Mexico New Mexico Texas New Mexico New Mexico Michigan Oklahoma Texas Oklahoma N2 N2 & sand N2 & sand N2 & sand N2 & sand N2 & HCl N2 & HCl N2 & sand N2 & ISP N2 & sand N2 & ISP HCl N2 & HCl N2 & wtr N2 & sand N2 & wtr 5769 5763 5763 5768 5697 14305 10823 9490 13021 5899 10784 3022 10231 12630 5921 11321 17 45 5 28 32 68 70 13 10 135 44 20 38 40 128 30 1980 1450 1650 1891 2058 11014 8000 2816 4771 2200 4336 640 4650 5827 1770 4653 0.424 0.756 0.120 0.003 0.003 0.018 0.006 10.8 0.24 0.109 7.955 0.500 0.039 0.006 0.081 0.051 Oryx Energy has so far had its greatest success in moderate to low permeability sandstones (25mD or less), high permeability-low BHP formations, and naturally fractured carbonates. How is it done? Conventional perforating guns are used, but a large overbalance is applied by pressurised nitrogen. If the pressure was applied using a liquid (brine or oil) it would dissipate too quickly after the gun was fired and the fractures at the tips of the perforations would not propagate. This is because brine and oil are essentially incompressible. However, if only nitrogen were used there would be no ‘mass’ to do work in the perforation. So the two methods are Typical land based overbalanced perforating operation Applied surface pressure = 7000 psi Illustration just prior to perforating Pressurized nitrogen Applied wellbore pressure 8000 psi (∆P = 5500 psi into perfs) Overbalanced Perforating 102 Sand. reservoir pressure = 2500psi Oil or fracture fluid Frac fluid will enter the perforations at 5500psi greaterpressure than the formation and will cause fractures to propogate from the tip of the perforations Revision 2: 2001 COMPLETIONS combined: the expanding gas provides the energy whilst a small column of incompressible fluid across the formation does the work. In normal applications, nitrogen is pumped at high rates instantaneously after perforation to extend the fractures. It is analogous to a bullet in which the slug provides the mass to penetrate the target when the powder behind is detonated. The technique is not widespread, and it is unlikely to take over entirely from underbalanced perforating. However it does have some application where: • permeability of the formation is so low that the perforation tunnels will not be cleaned out regardless of the underbalance used • low pressure reservoirs which may not have enough energy to backsurge the perforations • large intervals that must be perforated on wireline (several runs), where the later perforation runs can only be achieved with the well flowing, versus the desired full waterbalance Relative importance of four main geometrical factors in the three completion types, where 1 is the greatest importance and 4 is the least. The optimum perforation design establishes the proper trade-off of these factors, the lower part of the figure shows common considerations for perforating natural completions. When natural fractures are present, phasing becomes more important than density to improve communication between fractures and perforations. Schlumberger Oilfield Review Revision 2: 2001 103 WELL PRODUCTIVITY AWARENESS SCHOOL The present ‘Rule of Thumb’ for overbalanced perforating is: Minimum BHP Applied = (Fracture Gradient in psi/ft + 0.4) x Depth The sequence of a typical Oryx job might be: 1. Run TCP guns. Set on depth. 2. Using coiled tubing or circulating sub to place between 300ft and 1000ft of frac fluid across the interval and above the guns. 3. Pressurise up the nitrogen above the frac fluid to 7000 psi at surface. 4. Detonate guns. 5. Pressure drops instantly to approx 4400 psi. 6. Kick in nitrogen pumps at 8000-10,000 scf/min and pump 140,000 scf. 7. Produce well back. There are some problems with overbalanced perforating; primarily concerning equipment specification • can the wellhead, tubing, casing take the pressures? • have the well components been weakened over time by corrosion (if re-perforating at old well)? • are the tubulars CLEAN? • is the frac fluid non-damaging? 104 Revision 2: 2001 COMPLETIONS Sand Control Sand Control is implemented by one of the following methods • • • • • External gravel-pack Internal gravel-pack Pre-packed screen Chemical consolidation Frac pack In many wells, especially shallow ones, hydrocarbon production causes sand production. Unconsolidated sandstones with permeability over 0.5 Darcies are most susceptible to sand production, which may start during first flow, or later when reservoir pressure has fallen, or when water breaks through. Sand production strikes with varying degrees of severity, not all of which requires action. The rate of sand production may decline with time at constant production conditions and is frequently associated with clean-up after stimulation. Sand production may be tolerated depending upon operational constraints like resistance to erosion, separator capacity, ease of sand disposal, and the capability of any artificial lift equipment to remove sand-laden fluid from the well. Fluid inflow Cement Fluid inflow Perforation tunnel Formation sand Fluid inflow Doorway to the wellbore. A stable arch is believed to form around the entrance to a perforation cavity. This arch remains stable as long as flow rate and drawdown are constant. If these are altered, the arch collapses and a new one forms once flow stabilises again. Gravel a) Internal/External Gravel Packs and Pre-Packed Screens Gravel packs can be internal or external : using special tools, sized gravel is placed between the unconsolidated reservoir and the screen to prevent sand production. A pre-packed screen is a form of gravel-pack completion. The prepacked screen features a bonded resin-coated gravel held between an inner perforated base pipe and an outer wire-wrapped screen. Such completions are finding favour in unconsolidated horizontal wells, such as those of the Chevron Alba Field, Kerr-McGre’s Gryphon Field and BP’s Foinaven Field. Revision 2: 2001 Cementing port and/or external casing packer Slotted or pre-drilled liner, or wire-wrapped screen Gravel - must be placed in clean fluid to maintain the pack permeability (not often used nowadays) Underreamed hole must be drilled with non-damaging fluid EXTERNAL GRAVEL PACK - EGP 105 WELL PRODUCTIVITY AWARENESS SCHOOL Underreamed External Gravel Pack Frac Pack Resin Coated Sand Pack Plastic Consolidation Internal Gravel Pack DOWNHOLE SAND CONTROL METHODS 106 Revision 2: 2001 COMPLETIONS Dual-Screen Prepack Screen Perforated Base Pipe Gravel Inner wire-wrapped screen. This can be a mesh, rather than a stainless steel screen. Great care must be taken when handling all types of gravel-pack screens. They must be cleaned or kept clean at surface and handled very carefully. One point of weakness can lead to failure of the whole completion. They must be run in hole as carefully as possible to minimise damage and/or dirt pollution whilst scraping the wall of the wellbore. For long term productivity, the gravel must be clean, tightly packed and placed with the minimum damage to the formation. These requirements These screens are most commonly run in very high angle holes and horizontal should be used in the correct wells with sand control problems selection of gravel size, carrier fluid and placement technique. They also rely on scrupulous cleanliness during placement operations to prevent the contamination of the gravel pack by small particles that significantly reduce pack permeability. It has been proved that 0.5% fines in the gravel can plug the completion! Outer wire-wrapped screen The carrier fluids must be sufficiently viscous to carry the gravel to the completion downhole, yet they must ‘break’ completely after placement and flow back leaving no damaging residue. A carrier fluid is pumped with a time-delay (and temperature) breaker to facilitate this. Gravel is not just loosely sized sand. Gravel for gravel packing is a precisely graded, high quality product with strict limits of manufacture/production to minimise fines and impurities. Commonly Available Gravel Sizes Approximate Median Diameter Gravel Size (in.) 0.006 0.008 0.010 0.017 0.023 0.033 0.039 0.033 0.047 0.066 0.079 Revision 2: 2001 x x x x x x x x x x x 0.017 0.017 0.017 0.033 0.047 0.066 0.066 0.079 0.079 0.094 0.132 US Mesh Size In. µm 40/100 40/70 40/60 20/40 16/30 12/20 12/18 10/20 10/16 8/12 6/10 0.012 0.013 0.014 0.025 0.035 0.050 0.053 0.056 0.063 0.080 0.106 300 330 350 630 880 1260 1340 1410 1590 2020 2670 107 WELL PRODUCTIVITY AWARENESS SCHOOL Permeability and Porosity of Graded Sands US Mesh Permeability, Darcies (approximately) Porosity, % (approximately) 8/12 10/20 10/20 10/30 Angular Angular Round Round 20/40 40/60 Round Round 1,745 881 325 191 121 45 36 36 32 33 35 32 The pressure drop along the perforation tunnels in cased hole gravel packs gives high skins. Larger gravel gives a lower pressure drop and skin. However, since the pack must act as an effective filter, the gravel also has to be small enough to prevent the ingress of formation particles. The work of Saucier gives the most widely accepted criteria for gravel size selection, where gravel-size is six times the median diameter of the formation sand. In all cases the gap between each wire-wrap of the screen is exactly sized to compliment the gravel size used. Saucier also identified that wide entry holes, and large gravel-filled cavities behind the casing reduced the pressure losses in the perforations. This placement technique is now known as a 'pre-pack' where the perforations are purged by underbalanced perforating, followed by placement of gravel in a very clean filtered fluid. The perforations can then be protected by a degradable LCM which can be removed prior to placement of gravel between the screen and the perforations. Casing Cement Gravel pack Screen Perforation Formation sand Anatomy of a casedhole gravel pack. The gravel is placed in the perforations prior to the gravel being placed in the annulus. INTERNAL GRAVEL PACK - IGP 108 Revision 2: 2001 COMPLETIONS b) Sand Control Using Chemical Methods These techniques can be broadly divided into two categories; plastic (or in-situ) consolidation and use of resin coated sand. Historically, these techniques have been used as a low cost method of stopping sand production in short completed intervals. i) Plastic Consolidation The objective of the consolidation technique is to treat the formation in the immediate vicinity of the wellbore with a material that will bond the sand grains together at their points of contact. This is accomplished by injecting liquid chemicals through the perforations and into the formation. These chemicals subsequently harden and bond the sand grains together. For the treatment to be successful, three requirements must be met; a. the formation must be treated through all the perforations b. the consolidated sand mass remains permeable to well fluids c. the degree of consolidation should not decrease over time There are two main types of plastic consolidation treatment: Epoxy Resin: this is pumped in three stages. First a pre-flush containing isopropyl alcohol is pumped to reduce water saturation (otherwise consolidation is poor); then the epoxy is pumped; followed by a viscous oil to displace the resin from the pore spaces (to restore permeability). Shell use this treatment extensively in West Africa. It has some limitations: a) b) c) d) only 10 ft at a time can be treated reservoir temperature (40°C - 100°C) clay content (max=20%) formation water salinity. Furan and Phenolic Resins: these chemicals have a much higher temperature range than Epoxy but the consolidation is often 'brittle' and may fail prematurely. ii ) Resin Coated Sand Like a gravel pack, a resin coated sand pack is sized to hold back the formation sand; however, a resin coating, rather than a screen, holds the pack sand in position. Working through tubing, gravel pack sand is pumped via coiled tubing into the perforation tunnels and void spaces outside the casing. After the resin coating hardens and bonds the gravel together, this consolidated sand pack will prevent formation sand from entering the wellbore. Excess resin-coated sand is removed from inside the casing, usually by drilling it out. Some products mix the resin into the gravel slurry prior to pumping on location (e.g. Sandlock V process – externally catalysed) or the proppant is delivered to location already coated and formation temperature alone cures the resin, causing it to stick together (Bakerbond). Revision 2: 2001 109 WELL PRODUCTIVITY AWARENESS SCHOOL Sand Control Method Cased Hole GP (IGP) Open Hole GP (EGP) Milled Window, Underreamed GP Sand Consolidation No. of Wells 6 17 10 20 Productivity Impairment Skin Flow Eff. 25 6 11 2 22% 53% 38% 75% Brunei Shell assume an average skin of +40 (15% flow efficiency) for their IGPs. Although this is very low flow efficiency, a gravel pack installation allows higher sand free production rates than without a gravel pack, and hence the additional completion expense can usually be justified. SHELL SAND CONTROL EXPERIENCE; WEST AFRICA (GABON) All Types of Sand Control c) Frac-Pack Gravel packing is necessary for sand control (where sand consolidation treatments are inappropriate). Unfortunately (internal) gravel packing can cause skins of +10 to +50, even if strict cleanliness guidelines are followed. Some of the reasons for this, apart from dirty carrier fluids, might be: • • • • • • difficult to get all perforations effectively packed with gravel mixing of gravel and formation sand in perforation tunnels migrating fines due to high near well bore fluid velocities poor vertical communication in laminated reservoirs poor communication of the perforations to good reservoir quality rock trapped fines in the formation which might otherwise clean up To overcome these difficulties with high skins on IGP’s a technique that combines fracturing technology (see Section 5) with sand control was invented: the frac- pack.. The first evidence of frac-packs can be found in Venezuela in the sixties. The procedure did not appear to be adopted worldwide. In 1985 BP Alaska experimented with the ‘new’ technique called ‘Frac-Pack’ in the heavy oil deposits. The treatment which combines frac-stimulation technology with gravelpacking, was successful; but the heavy oil development was halted due to global oil economics. However, the technique has now reached fruition in the Gulf of Mexico, where the technology has become increasingly refined, resulting in an average 2-3 fold increase in productivity compared with IGP’s, and skins of zero, or even negative values. 110 Revision 2: 2001 COMPLETIONS Note: Frac-packs do not have to be selectively perforated. Screen Casing Cement Damaged Zone Frac-pac with proppant Weak layer of reservoir not perforated Consolidated formation STRONG Layer requiring sand control WEAK Consolidated formation STRONG Stronger levels (not prone to sand production) of reservoir perforated. Oil from weaker layers flows through the frac to the perforations without producing sand SPECIAL APPLICATION OF FRAC-PACK The frac-pack procedure creates a relatively short, highly conductive fracture which will breach the near-wellbore damage, reduce the drawdown and nearwellbore velocity and stresses, and increase the effective wellbore radius. The treatment has three key stages: i) formation breakdown - fracture initiation ii) fracture created - terminated by tip screen-out. iii) fracture inflation and packing. The most important criteria for a good frac-pack is fracture conductivity . The proppant - or gravel - in the frac needs therefore to be as coarse as possible; but this conflicts with the requirement that proppant size should be kept small for effective sand control. Initially the gravel in frac-packs was sized according to Sauciers criteria (d5o of the proppant should equal five to six times the d5o of the formation sand). However the situation in a frac-pack well is different from a gravel-packed well, since the fluid velocities are lower in a frac-pack and the same production can be achieved with a lower drawdown. Operators have found that they are able to put a larger proppant in a frac-pack than Saucier’s criteria suggests. In the Amberjack Field, for instance, BP have stepped up from a 40/60 gravel to 20/40 ceramic beads (larger particles = larger pore-throats; more even round grains = enhanced permeability) without loss of sand control. Skins have gone from +3 to -0.5. A frac-pack does not get away from the need for a screen in the well, unless resin-coated gravel is pumped. At present most frac-pack wells are completed with screens, but there is an increasing pace in the development of resins and resin-coated gravel. Revision 2: 2001 111 WELL PRODUCTIVITY AWARENESS SCHOOL A special application of this type of treatment has been successfully pioneered by Oryx Energy in the USA, where resin-coated gravel slurries are used in overbalanced perforating. The very high perforating pressures fracture the perforation tips, and the instantaneous pumping (of nitrogen) behind the slurry packs the new mini-fractures. d) Cleanliness A gravel packed well will nearly always have a positive skin.This is a necessary evil to prevent sand production. However, all efforts must be made to minimise this skin. This is very much an area where everyone on the rig can influence the success of a well. All equipment, tanks, lines and tubulars must be very very clean. All fluids must be filtered. Completions must use minimal tubing dope. Remember that the gravel pack will effectively stabilise any formation damage existing in the formation. It is therefore imperative that as much damage (e.g. filter cake, filtrate, perforation debris) be removed as possible prior to the gravel-pack being placed. 112 Revision 2: 2001 COMPLETIONS Intersected Natural Fracture Hydraulically-Induced Fracture Deviated Hole BETTER THAN BASE CASE PERFORMANCE Partial Penetration Fractured Reservoir Poor Perforation Formation Damage Low K POORER THAN BASE CASE PERFORMANCE Revision 2: 2001 113 WELL PRODUCTIVITY AWARENESS SCHOOL The wells are now cased and perforated: Cased and perforated well. No formation damage. Poorly perforated. No formation damage Production Rate 10040 bopd Skin = -0.9 Production Rate 7200 bopd Skin = +1.9 Cased and Perforated 16" Perforations, 6 spf, 80 degree No Damage Fully Completed Vertical Cased and Perforated 8" Perforations, 2 spf, 180 degree No Damage Fully Completed Vertical The equivalent undamaged open hole completion with a skin of zero produced 8910 bopd. WASP-3: Same reservoir as Wasp-1 Well is now cased and perforated Same reservoir as but with formation damage. Production Rate 6480 bopd Skin = +3 Cased and Perforated 16" Perforations, 6 spf, 80 degree 80% Permeability Reduction 2 Feet of Invasion Fully Completed Vertical 114 Revision 2: 2001 COMPLETIONS Completion Skin: Good Perforations Drilled with Poor Mud Giving Damaged Zone. Well Engineered Perforations Production Rate 9380 bopd Skin = -0.4 Cased and Perforated 16" Perforations, 6 spf, 80 degree 80% Permeability Reduction 1 Foot of Invasion Fully Completed Vertical The equivalent open hole completion had a Skin of +5.4 and produced 5320 bopd. Deeper Invasion Perforations Cannot Reach Past the Damaged Zone. Production Rate 6480 bopd Skin = +3 Cased and Perforated 16" Perforations, 6 spf, 80 degree 80% Permeability Reduction 2 Feet of Invasion Fully Completed Vertical The equivalent open hole completion had a Skin of +7.6 and produced 4570 bopd. Completion Skin: Poor Perforations One Foot of Invasion Very Poorly Perforated Production Rate 3100 bopd Skin = +15 Cased and Perforated 8" Perforations, 2 spf, 180 degree 80% Permeability Reduction 1 Foot of Invasion Fully Completed Vertical Two Foot of Invasion Very Poorly Perforated Production Rate 2830 bopd Skin = +17.2 Cased and Perforated 8" Perforations, 2 spf, 180 degree 80% Permeability Reduction 2Feet of Invasion Fully Completed Vertical The equivalent open hole completion had a Skin of +5. Revision 2: 2001 115 WELL PRODUCTIVITY AWARENESS SCHOOL Completion Skin: Partial Penetration (of Reservoir) Same reservoir as Wasp-1 but only partially completed. Same reservoir as Wasp-5 but with Formation Damage. Production Rate 6250 bopd Skin = +3.4 Production Rate 4980 bopd Skin = +6.3 Open Hole No Damage Top 100 ft Completed Vertical Open Hole 50% Permeability Reduction 2 Feet of Invasion Filter Cake Removed Top 100 ft Completed Vertical WASP-5 Completion Skin: Deviated Well Same reservoir as Wasp-1 but drilled at high angle. Same well as Wasp-6 but with formation damage. Production Rate 11500 bopd Skin = -1.8 Production Rate 6360 bopd Skin = +3.2 Open Hole No Damage Filter Cake Removed Fully Completed 55 Degrees Open Hole 80% Permeability Reduction 2 Feet of Invasion Filter Cake Removed Fully Completed 55 Degrees WASP-6 116 Revision 2: 2001 COMPLETIONS Same reservoir as Wasp-6 and same inclination, but cased and perforated. Same well as Wasp-7 but with formation damage. Production Rate 12980 bopd Skin = -2.5 Production Rate 9140 bopd Skin = -0.2 Cased and Perforated 16" Perforations, 6 spf, 60 degree No Mud Damage Fully Completed 55 Degrees Cased and Perforated 16" Perforations, 6 spf, 60 degree 80% Permeability Reduction 2 Feet of Invasion Fully Completed Vertical WASP-7 Completion Skin: Gravel Packs Same Reservoir as before. External Gravel Pack necessary. Production Rate 6310 bopd Skin = +3.3 Open Hole (Under-reamed to 12.25") 10D Gravel No Mud Filtrate Damage Fully Completed Vertical WASP-8 Revision 2: 2001 Same well as Wasp-8 but with Internal Gravel Pack Production Rate 5940 bopd Skin = +4 8" Perforations, 0.6" Diameter 6 spf, 90 degree Phasing 10D Gravel No Mud Damage Fully Completed Vertical 117 WELL PRODUCTIVITY AWARENESS SCHOOL Completion and Mechanical Skin in Gravel Packs Same well as before, IGP but in Damaged Formation Same well as before but Formation Severely Damaged Production Rate 4570 bopd Skin = +7.6 Production Rate 2120 bopd Skin = +25.6 8" Perforations, 0.6" Diameter 6 spf, 90 degree Phasing 10D Gravel 40% Permeability Reduction 2 Feet of Invasion Fully Completed Vertical 8" Perforations, 0.6" Diameter 6 spf, 90 degree Phasing 10D Gravel 80% Permeability Reduction 2 Feet of Invasion Fully Completed Vertical Example of Frac-Pac to overcome high gravel-pack skin Production Rate 8910 bopd Skin = 0 8" Perforations, 0.6" Diameter 6 spf, 90 degree Phasing 10D Gravel Mud Damage Bypassed By Fracture Fully Completed Vertical 118 Revision 2: 2001 COMPLETIONS Revision 2: 2001 119 WELL PRODUCTIVITY AWARENESS SCHOOL 120 Revision 2: 2001 S T I M U L AT I O N Stimulation 122 Acidisation Candidates for Acidisation Acid Systems a. Hydrochloric Acid b. Mud Acid c. Organic Acids d. Additives 123 124 124 125 127 127 Treatment Types a. Bullheading vs. Coiled Tubing b. Acid Washes c. Matrix Acidisation d. Acid Fracs 128 128 130 130 134 Formation Damage During Acidisation a. Corrosion b. Iron Reprecipitation c. Fluid Incompatibilities d. Fines Mobilisation e. Liquid Block in Gas Wells f. Cement Bond Destruction g. Prevention 135 135 135 135 136 136 137 137 Microbes as an aid to Well Production 139 Hydraulic Fracturing 141 Basics of Fracturing Treatment Types a. Acid Fracs b. Propped Fracs 141 145 145 145 Identifying Candidates a. Gas Wells b. Oil Wells c. Conventional & Tip Screen Out Treatments d. Deviated & Horizontal Wells e. Water Injectors 148 149 150 150 151 153 Formation Damage During Fracturing 153 MODULE SUMMARY Revision 2: 2001 123 156 121 WELL PRODUCTIVITY AWARENESS SCHOOL Stimulation At the end of this module you should be aware of: • The types of well which may benefit from stimulation • When to consider acid stimulation • When to consider hydraulic fracturing • How damage can occur during stimulation treatments • Techniques to improve stimulation performance • Potential improvements in productivity after stimulation • Typical skin factors expected after stimulation Why Stimulate Native permeability very low. ? To by-pass near-wellbore damage Low K Why would we stimulate a well in the first place? There are two main reasons: either the native permeability of the reservoir is so poor in the first place that the well/field is not economically viable, and would not be produced without stimulation, such as some southern N. Sea gas wells/fields; or the near-wellbore region has been damaged and a stimulation treatment is necessary to by-pass the damage and restore the well productivity. The first reason is unavoidable; the second is best avoided by not damaging the well in the first place. Generally, acid stimulation is most suited to carbonate formations and for the clean-up of acid soluble damage, carbonate muds and kill pills; hydraulic fracturing to low permeability sandstones and formations with non-soluble formation damage.. STIMULATION - as a general rule ... ! Hydraulic Frac Acid 122 Most suited to CARBONATE Formations Most suited to Low Permeability Sandstones Removing acid soluble damage Fracturing past formation damage Revision 2: 2001 S T I M U L AT I O N Prevention is better than Cure Formation Damage cannot always be removed by acid. Consider your choice of mud and completion fluid carefully Acidisation Candidates for Acidisation Acid will not solve all well productivity problems. Acidisation is fraught with problems and can damage a formation rather than stimulate it, if the job is not planned properly. Not all wells can be improved with acid. Before contemplating an acid job, the well/wells must be studied carefully to see whether or not they will truly benefit. There may be reasons other than formation damage that are restricting productivity. Causes of Poor Productivity Other Than Acid Soluble Damage High liquid/gas ratio in a gas well >100 bbl/MMscf High gas/oil ratio in an oil well >1000 scf/bbl Three phase production: water, oil and gas High pressure drawdown >1000 psi High Flow Rate >20 bbl/day/ft > 5 bbl/day/shot Sub-optimal perforating Inefficient lift in the tubing = Non-Dary effects in gas wells = turbulent flow = pressure losses Completion skins Gas breakout if producing below bubble point In general, an acid job falls into one of three categories: i) Hydrochloric acid (HCl) in carbonate reservoirs to etch new channels of communication ii) Hydrochloric acid in a damaged carbonate-cemented sandstone to create channels to by-pass the damage iii) Mud acid (HF) in low-carbonate sandstones, to remove mud damage or soluble fines. Organic acids (formic and acetic) do the same job as HCl but they are weaker and act at slower rates. Revision 2: 2001 123 WELL PRODUCTIVITY AWARENESS SCHOOL ACID TYPES FORMATION HCI HF Acetic Carbonates Sandstones (>15% carbonates) Sandstones (<15% carbonates) Think carefully about what you want the acid to do, before you start designing the acid job and ordering the chemicals and equipment. Acid Systems a) Hydrochloric Acid Hydrochloric (HCl ) is the most widely used acid. A concentration of 15% is most common, but 7.5% and 28% can also be found. It dissolves carbonate materials such as calcite, dolomite and siderite. Iron oxide (rust) is also dissolved, or just dislodged from the tubing.. 2HCl + CaCO 3 ⇔ CaCl 2 + H2 O + CO2 Matrix acidising of carbonates started as long ago as 1896 in the USA. Hydrocarbon production was found to increase by three to four fold, but the treatments severely corroded the casing. Thus the popularity of this stimulation declined until 1931 when Dr. John Grebe of the Dow Chemical Company discovered that arsenic inhibited the action of HCl on metal. The volume of work that this generated led to the founding of Dowell. 124 Revision 2: 2001 S T I M U L AT I O N DENDRITIC PATTERN OR ‘WORMHOLES’ FORMED BY HYDROCHLORIC ACID IN A CARBONATE It is important that the acid reaction only produces soluble products. Some impurities in limestone and dolomite are insoluble in acid, and if appreciable percentages of such components are present, special additives must be included in the acid solution to ensure their removal. b) Mud Acid Mud Acid is a mixture of hydrofluoric acid (HF) and hydrochloric acid, usually 12% HCl and 3% HF, but low strength mud acid (6% HCl and 1.5% HF) is also used. Mud acid is used primarily to remove clay-particle damage in sandstone formations, to improve near-wellbore permeability of clay-containing formations and to increase solubility of dolomitic formations. Its utility is based on the fact that some clays, silica, and other materials, normally insoluble in HCl, have some degree of solubility in HF. HF+'clay' → Si,Al in solution quickly HF+'quartz' → Si in solution slowly ( H 2 SiF 6 ) H2SiF 6 +'clay' → Al + Si( OH) 4 amorphous silica precipitate Revision 2: 2001 125 WELL PRODUCTIVITY AWARENESS SCHOOL 0.4 0.4 MUD ACID 0.3 0.3 0.2 0.2 0.1 MUD ACID 0.1 REGULAR ACID (HCl) HCl 0 0 6 12 18 Time of Contact in Hours 0 24 0 Solubility of Bentonite in Acid 6 12 18 Time of Contact in Hours 24 Solubility of Silica Sand in Acid HF reacts with sodium, potassium and calcium to form insoluble precipitates. HF may also produce insoluble by-products such as colloidal silica as a result of actions with the rock. Consequently a pre-flush of HCl must always be used to: a. b. c. Displace formation water containing potassium, sodium or calcium ions. If this is not done a range of fluosilicates {e.g. K2SiF6} or fluoaluminates of varying solubility can form due to the HF reaction. Maintain a low pH in the near wellbore region throughout the treatment to avoid various precipitation reactions. Dissolve carbonates which could produce insoluble fluorides (e.g. CaF2). Never use HF with Carbonates Mud Acid HF + CaCO3 = CaF2 + CO2 + H2O Always pre-flush the formation with HCI to remove carbonates Also remove sodium, potassium and calcium ions to prevent the formation of insoluble fluosilicates and fluoaluminates Precipitate = Formation Damage The fluid used to displace HF should not contain sodium, potassium or calcium ions. Ammonium chloride, HCl or diesel is often used to flush the near wellbore area immediately following the mud acid; thus if any precipitates are formed they are as remote as possible from the near-wellbore region. + H 2SiF 6 + 2K → K 2SiF 6 precipitate CaCO 3 + 2HF → CaF 2 precipitate + CO2 + H 20 126 Revision 2: 2001 S T I M U L AT I O N c) Organic Acids These acids are used less frequently, although there is an increasing tendency to use them to remove carbonate LCM in gravel-packed completions. Organic acids (acetic and formic ) dissolve carbonate materials in the same manner as HCl but at a much slower rate. These are used in high temperature wells (greater than 250°F), or those with high alloy tubing (e.g. 316 stainless steel in wire-wrapped screens), where unacceptably high corrosion rates would otherwise be obtained with HCl (even with corrosion inhibitor). The slower reaction rate also allows use of these acids to achieve deeper penetration in carbonates, where HCl would spend quickly in the vicinity of the wellbore. The maximum concentration for Formic Acid used in the field is 15%; otherwise insoluble calcium formate will precipitate. Likewise acetic acid is never used in concentrations greater than 10% or calcium acetate is precipated. d) Additives i) Corrosion Inhibitors These are generally dissolved in the acid to eliminate 95% to 98% of the metal loss that would otherwise occur. Most inhibitors have practically no effect on the reaction rate of the acid with the formation. The length of time an inhibitor is effective depends on the acid temperature, type of acid, acid concentration, type of steel, and inhibitor concentration. Be aware that these inhibitors are often highly damaging since they can change the wettability of the formation. ii) Surfactants Surfactants are chemicals that are used to lower the surface tension or interfacial tension of fresh acid or spent acid solutions. This allows the acid to penetrate deeper into a formation, and allows easier passage of spent acid when the well is produced back. Surfactants also act as demulsifiers to inhibit the occurrence of emulsions (acid/oil) or destroying those already formed. A mutual solvent is a form of surfactant that helps prevent the formation of sludges or emulsions, and may assist in particle migration/clean-up by preventing the stabilisation of emulsions by fine particles. A mutual solvent can also remove a damaging oilwetting phase from a rock (for instance where oil-based mud has rendered a previously water-wet rock oil-wet, thus forcing the water into the pores causing a blockage) and surfactants can re-establish the water-wet conditions allowing the oil to flow. iii) Clay Inhibitors These prevent various clays and silts from swelling and blocking pores and pore throats. iv) Iron Control Agents A sequestering agent prevents the precipitation of iron salts when the acid spends. Revision 2: 2001 127 WELL PRODUCTIVITY AWARENESS SCHOOL A reducing agent will convert ferric ions to ferrous irons, and these will not precipitate until the pH is above 7 (which will not happen in the spent acid). In a sour well, where H2S is present, complexing agents are needed to prevent the precipitation of ferrous sulphide. v) Gelling or Fluid Loss Agents Natural gums and synthetic polymers are sometimes added to the acid to increase the viscosity of the acid solution to slow down its leak-off into large pores or fractures. vi) Nitrogen Nitrogen can be added to the acid to energise it; to assist flowback and clean-up. vii) Retardants To slow down the reaction of the stimulation, either slower-acting acids such as formic and acetic acids may be used, or retardants are mixed with HCl or HCl/HF. Treatment Types Two things need to be considered here • how are we going to get the acid to the reservoir? • what sort of acid job are we going to perform? a) Bullheading vs. Circulating Acid Treatments Methods of getting acid to the formation Bullheading down production tubing OR Circulating via Coiled Tubing OR Circulating via Dedicated Work String Beware of potential damage from rust, scale, dope or dirt being forced into the formation. Coiled tubing may restrict rates Dedicated work string must be scrupulously clean ACID WASH = Small volume Cleans perforation only MATRIX ACIDISATION = Large volume Full acid job reaching the rock matrix well into the near wellbore region Pumped at below frac pressure ACID FRACS = Fracturing of rock with acid medium to etch the surface of frac 128 Revision 2: 2001 S T I M U L AT I O N In 1990 Paccaloni of AGIP studied 650 matrix acidising jobs world-wide. He estimated that 12% were outright failures; and that 73% of these failures were due to poor field practice. Just 27% of the failures were caused by incorrect choice of fluids and additives. Reasons for poor field operation centred on the technique of bullheading ; when acid is pumped into the well down the tubing, pushing dirt, scale, rust and dope from the tubing, and whatever fluids are below the packer – often mud – directly into the formation. Therefore, wherever possible, coiled tubing or a dedicated workstring should be used to circulate the acid into place and then pump it away. Check that these are clean and not recently used for a cement job (the acid will dissolve residual cement, and carry it into the formation where it will plug). Coiled tubing reel Matrix fluid tank Pump unit Injector head BOPs Coiled tubing Circulating valve Matrix acidizing with the Formation Selective Treatment (FSTS) system on coiled tubing. The FSTS tool comprises an injection port between two inflatable packers. A circulating valve just above the tool obviates the need to push large volumes of well fluid into the formation before the acid. For less efficient spotting of acid, coiled tubing can be pushed to the end of the hole and slowly withdrawn while acid and diverting agents are pumped. Liner Schlumberger Oilfield Review MATRIX ACIDISING THROUGH COILED TUBING AND STRADDLE PACKER If the choice of treatment precludes the use of coiled tubing (e.g. the ball sealers will jam in the CT or CT does not permit the desired rates and/or pressures) then take all the precautions possible to ensure that the tubing is clean, even to the extent of ‘flexing’ (pressure the string to cause ballooning of pipe to break off any flakes of rust) and ‘pickling’ it with acid before the main job is pumped. The ‘dirty’ sump fluids might be circulated out in a similar manner, and replaced with a clean non-damaging fluid. Everything must be done to avoid ‘solids’ getting into the perforations and the formation, where they will cause permanent damage. If a dedicated work string has to be run then the well might have to be killed – which might itself cause damage! Revision 2: 2001 129 WELL PRODUCTIVITY AWARENESS SCHOOL b) Treatment Type i) Acid Washes Acid is circulated past the perforations, often with coiled tubing; pumping is then stopped and the acid allowed to feed into the formation under hydrostatic pressure (sometimes a small pressure is applied). The treatment is rarely longer than one hour, and the well is immediately produced back to remove the acid and its by-products. ii) Matrix Acidisation The simple aim of matrix acidising is to dissolve away formation damage or create new pathways within several inches to a foot or two around the wellbore. The treatment is pumped at a pressure below formation fracture pressure. The volume of acid pumped (per foot of perforation) can be calculated in the same manner as the depth of invasion. To penetrate 3 ft into a formation in an 8 1/2” wellbore will require approximately 42 gallons of acid per foot of reservoir. Often volumes are much higher: at 50-100 gallons/ft. Formation damage mineralogy Diagnostics Well completion data Damage type Damage removal mechanism Fluid selection adviser 3% HF, 12% HCl Fluid description Fluid sequence Risk analysis Pumping schedule advisor Volumes Number of diverter stages Injection rates Preflush 15% HCl, Surf, Cor. Inh. Main flush 3% HF, 12% HCl, Surf. Overflush 5% HCl, Surf, Cor. Inh. Simulator Flow profile evolution Skin evolution Rate/pressure plots Production prediction Production rates Payout time PLANNING A MATRIX STIMULATION 130 Product mapping Preflush 15% HCl, F78, A260 Main flush RMA, F78, A260 Overflush 5% HCl, F78, A260 Schlumberger Oilfield Review Revision 2: 2001 S T I M U L AT I O N It is important to understand the ‘reaction rate’ of an acid you plan to use. This, correlated with reservoir and formation characteristics, form a guide for the selection of acid type and the volume for a given treatment. Next, a study of these factors can furnish an understanding of what parameters govern spending time, which will determine how far a given formulation can penetrate into a formation before spending. Many factors govern the spending rate of an acid, such as pressure, temperature, flow velocity, acid concentration, reaction products, viscosity, acid type, area/volume ratio, and formation composition (physical and chemical). What is going to affect the acid reaction rate and therefore how deeply the stimulation is effected? • ACID TYPE • PRESSURE • TEMPERATURE – Choose the acid that will dissolve more rock/damage – Above 500 psi pressure does not have much effect in acid reaction rates – Higher temperatures lead to faster reaction rates. Remember that the injected acid will cool the formation • FLOW VELOCITY – Increased flow velocities can increase reaction rates • ACID CONCENTRATION • AREA/VOLUME RATIO – With HCl, higher concentration leads to faster reaction, up to 25% – The area in contact with the acid over a given time; inversely proportional to the pore radius or fracture width - more area leads to quicker reaction. For example, a 10mD, 20% porosity limestone may have an A/V ratio of 28,000 to 1. In such a formation it would be difficult to obtain significant penetration before spending If pumping an acid treatment to remove formation damage, HCl acid in a carbonate will tend to etch new paths around any formation damage; whereas mud acid in sandstones will try and dissolve away the actual damage itself. A pre-flush is pumped to flush out any undesirable minerals/fluids in the rock. This is followed by the acid itself; followed by a postflush to push the spent acid back into the formation and away from the near-wellbore region (to push any potential damage as far away from the well as is practical). Apart from the insoluble precipitates that may form in a sandstone acidisation, there is always the risk of mobile fines being generated; thus it is sometimes recommended that injection rates be decreased and/or that retarded systems be used to slow down the acid reaction to try and prevent fines being dislodged. Dowell have recently introduced a retarded system utilising fluoboric acid (HBF4) that reacts with (formation) water to generate HF in situ (sometimes known as Self-Generating Mud Acid). The slow rate of this conversion allows deep penetration of the HBF4 and thus of HF. As a bonus, the fluoboric acid itself reacts with the clays and silt, forming borosilicates that appear to help bind the fines to large sand grains. Revision 2: 2001 131 WELL PRODUCTIVITY AWARENESS SCHOOL 4000 3000 Mud acid treatment 2000 1000 0 Fluoboric acid treatment 0 1 Production improvement in a Nigerian oil well after fluoboric acid treatment. The well was initially acidized with mud acid and produced 850 barrels of liquid per day (BLPD) with a 34% water cut. Production then declined almost to zero, most likely due to fines movement. After fluoboric acid treatment, production rose to 2500 BLPD, obviating the need for further acid treatments. Oil production a year after the treatment was 220 BOPD. 2 Time, yr Schlumberger Oilfield Review USE OF CLAY STABILISER TO PREVENT FINES MOVEMENT An important part of matrix acidising is the ‘art’ of diversion . Diversion of acid is necessary, because in the treatment of a large interval (more than 10 ft), the first acid to hit the formation will generally enter the zone that already has the least damage or the best permeability, and it will increase the permeability of that immediate area even further (if the design is correct!). Subsequent acid preferentially enters this zone and the remainder of the interval will receive little or no stimulation, unless the acid is diverted. Various methods of diversion can be used: Why Diversion? Without diversion all the acid would go into the most permeable zone or the least damaged and the majority of rock would remain unstimulated. A properly planned diversion should ensure that all the reservoir is stimulated. Straddle packer: a positive means of diversion, where twin packers are used to isolate intervals one at a time. The method is effective but costly because of the time taken. Ball sealers: these are nylon balls with hard cores that are designed to seal across any perforation taking acid. Ideally the balls have a density close to, or slightly less than, the acid. The treatment is pumped in stages: preflush; acid; ball sealers; acid; ballsealers, acid etc. (A postflush might be pumped after each acid stage). Buoyant balls are caught in ‘ball-catchers' at surface; if the balls are heavier than the fluids they sink to the bottom of the rathole. Particle materials: benzoic acid flakes which dissolve in hydrocarbons, oilsoluble resin and materials that melt at a certain temperature are used as diverting agents. They are added continuously or intermittently to build up a filter cake across any interval taking acid. Clean up of these agents after a treatment can be a problem, i.e. not all the oil-soluble resin may dissolve in the produced oil. Particulate diverting agents are generally not effective in fractured formations. 132 Revision 2: 2001 S T I M U L AT I O N DIVERSION Particulate Diverters - Benzoic Acid - Oil Soluble Resin - Temp sensitive chemicals Ball Sealers Balls are pumped down the well and seal against the zone taking fluid at that time Straddle Packer - Expensive - Accurate Foam Acid will now flow into the untreated portion of the reservoir - Nitrogen & soap - Blocks by surface tension - Efficiency improved by surfactant F o a m : foamed acid is becoming popular, but relative permeability effects make it difficult to pump large amounts of acid into any given interval. Foamed acid is useful in diverting a long horizontal section in an open-hole completion. Openhole completion? Chemical Gravel packed? Yes No Chemical Coiled tubing available? Yes No Mechanical Yes No Chemical Staged treatment required? Yes No Chemical Flowback of balls a problem, or high shot density? Yes No Mechanical ball sealers CHOOSING A DIVERSION METHOD FOR MATRIX ACIDISING Revision 2: 2001 133 WELL PRODUCTIVITY AWARENESS SCHOOL Generally a matrix acidisation is far cheaper method of stimulation than a ‘frac treatment’ (with or without acid), but unfortunately acidisation is not always the best way to increase productivity. Stage 1 Stage 2 1 2 3 4 5 6 7 8 Step Fluid Volume bbl Flow rate bbl/min Time min Preflush Main fluid Overflush Diverter slug Preflush Main fluid Overflush Tubing displ. HCl 15% RMA 13/31 HCl 4% J237A2 HCl 15% RMA 13/31 RMA 13/31 4% HCl NH4Cl brine 3% 17.3 68.2 33.0 3.1 17.3 55.6 53.7 33.0 2.2 2.2 2.4 4.8 4.8 1.1 1.1 1.2 7.9 31.0 13.8 0.6 3.6 50.5 48.8 27.5 1. Regular Mud Acid, 13% HCl, 3% HF. 2. Four-micron particulate oil-soluble resin, usable up to 200 °F. TYPICAL STAGED MATRIX ACID JOB Time for pumping = 3 hrs iii) Acid Fracs for Carbonates In acid fracs, HCl is used in carbonates to create a conductive fracture which can bypass damage and/or stimulate low permeability formations. The faces of the fracture are etched by the acid, so that after the fracture closes, some flow channels remain open. It is not effective where: a. b. c. The rock has an acid solubility of less than 80% The rock is too soft to support an etched fracture – a Brinnell hardness of at least 100MPa is recommended; and if porosity is greater than 40% problems can also be expected. Core testing is necessary to ensure a successful treatment. The conductivity of acid fractures can reduce with time, so in some instances propped fracturing should be considered in carbonates (e.g. in chalk). Acid fracturing in sandstones is not a common practice. 134 Revision 2: 2001 S T I M U L AT I O N Formation Damage During Acidisation This section is critical: too many people plunge ahead with acid jobs thinking that it will solve all their problems, without first considering the downside. FORMATION DAMAGE DURING ACIDISATION ‘Pickle’ the tubing before pumping any acid to minimise damaging ferric irons in the spent acid Use corrosion inhibitors – but beware that excess inhibitor could itself cause damage Corrosion Fluid Incompatibilities Iron Precipitation ACID Liquid Block in Gas Wells Fines Mobilisation Beware of acid and oil forming an emulsion or sludge – possibly encouraged by iron in the acid. Beware of acid mixing with remains of oil-based mud. Beware surfactants. caused by spent acid (esp. in low pressure wells.) HCI may cause silica fines to be released from clays. HF may precipitate silica fines. a) Corrosion Acid dissolves the tubing. This is minimised by adding corrosion inhibitor. Most corrosion inhibitors are not soluble in acid and, if used in excessive quantities, will damage the formation by changing the wettability. Particular care is needed in chrome tubulars where special inhibitors are required. b) Iron Reprecipitation The pH of spent acid will rise, which can reprecipitate any iron that has been dissolved. The damaging ferric ions are dissolved from the wall of the tubing as the acid is pumped downhole. To avoid this it is good practice to ‘pickle’ the tubing before the treatment by pumping acid to the end of the tubing and then reverse circulating it out with the dissolved iron. This will also remove any other debris that might be removed from the walls of the tubing during acidisation. c) Fluid Incompatibilities Acid may form emulsions or sludges on contact with formation oil. Drilling muds, especially oil-based muds, which may still be in the near wellbore region, can also create emulsion problems. Sludge precipitation can be encouraged by iron in the acid. Various surfactants can be pumped to alleviate these problems, but remember that surfactants themselves can cause problems. Revision 2: 2001 135 WELL PRODUCTIVITY AWARENESS SCHOOL d) Fines Mobilisation Although HCl does not dissolve clays it does react with them, leaching aluminium out of the structure. This process produces silica fines which can reduce permeability. A ‘pH shock’ can also disperse clays, or they can be dispersed by the dissolution of carbonate cements.. Consequently, HCl acidisation of clay-rich sandstones can cause a permeability reduction if this is not offset by the removal of acid soluble material. Minerals Surface Area Solubility HCl Solubility HCL-HF Quartz Chert Feldspars Micas Low Low to Moderate Low to Moderate Low No No No No Very Low Low to Moderate Low to Moderate Low to Moderate Kaolinite Illite Smectite Chlorite High High High High Very Low* Very Low* Very Low* Very Low** High High High High** Calcite Dolomite Ankerite Siderite Low to Moderate Low to Moderate Low to Moderate Low to Moderate High High High High High, but CaF2 Precipitation High, but CaF2 Precipitation High, but CaF2 Precipitation High * Aluminium and other elements can be leached out of clay minerals leaving insoluble silica ** Iron removed from chlorite causes potential iron reprecipitation problems Mineral-Acid Solubility Mud acid can also cause fines dispersion, in addition, as HF spends itself on clay minerals it can also precipitate silica. This can cause a permeability reduction if an excessive amount of acid is used. The problem of fines migration and permeability loss is most pronounced in low permeability sandstones, as their smaller pore sizes are more prone to plugging. In high permeability sandstones the movement of the fines might weaken the rock, causing sand production problems. Due to the sensitivity of low permeability clay-bearing sandstones, low strength mud acid is often used in an effort to minimise these adverse effects (acetic acid and acid-methanol mixtures have been other alternatives). Clay stabilising treatments have also been used on such rocks after the acid treatment, to try and minimise the movement of fines after the job. e) Liquid Block in Gas Wells In gas wells, especially low pressure gas wells, spent acid may create a ‘water block’ around the well. This can take some months to clean up or may 136 Revision 2: 2001 S T I M U L AT I O N permanently block production (in West Sole after workover and acidisation, production takes about six months to return to normal). The effect can be reduced by the use of surfactants and/or mutual solvents. Alternatively, by adding nitrogen to the acid a speedy recovery can be encouraged. f) Cement Bond Destruction Hot HCl/HF acid can break down cement bonds. This is especially a problem where poor primary cementing leaves channels in the cement, or where a previous squeeze cement job has been used to block off water. Arco Alaska have developed a latex-blended cement that is more resistant to acid. g) Prevention Pre-job Planning PREVENTION OF ACID DAMAGE • Check acid compatibility with: – – – – formation oil formation water tubing • Do tests with simulated spent acid iron content. Use fresh oil where possible - oil ages with time a. Acid compatibility with the oil, brine, old oil-based mud, tubing, and formation must be checked when planning the job. Check for formation of emulsion and sludges. Make sure that all acid additives are also checked with the acid. Carry out return permeability measurements. When checking acid compatibility with formation water, do so with a simulated iron content of the spent acid and at reservoir temperature. Where possible use fresh oil, as oil ages with time. On Site PREVENTION OF ACID DAMAGE • Check specifications of all chemicals delivered to site • Batch mix treatment • Check that everything is ‘as per design’ • Check that all pipework and equipment is clean (hardware previously used for a cement job is unsuitable) Revision 2: 2001 137 WELL PRODUCTIVITY AWARENESS SCHOOL Stimulated Completion Perforation Technique Selection It is undetermined whether the well needs stimulation. Could underbalance perforating eliminate the need for stimulation? or Stimulation is required. Is any added operational complexity of underbalance perforating justified by the likely improvement in well cleanup and stimulation? No Yes P erforate overbalance Perforate underbalance (see underbalance perforating in Natural Completion flowchart) Will perforation be performed through workstring? Yes No Through-tubing guns Will stimulation benefit from high shot density or reduced phase angle? (wireline conveyed) Yes • Will gun or charge debris be a problem for downhole equipment? or • Are more than two zones to be perforated selectively? Yes Select correct diameter of scallop or high shot density gun compatible with downhole restrictions; select phasing and shot density. Boxes in red outline denote final decision points. Select correct diameter high shot density gun compatible with downhole restrictions; select phasing and shot density Casing guns (wireline conveyed) No Exposed guns Is well deviation ≥ 60° or is the interval long enough to justify running on tubing? Yes No Tubing conveyed Wireline conveyed Are uniform and circular entrace holes a high priority? and Is 12-in. API section 3 Yes Selectric system THIS APPLIES FOR ACID AND FRAC STIMULATION 138 No No Is limited entry perforating required? Yes No Is the well ≤ 4000 psi, <210°F [99°C]? Yes No High Energy Guns Port plug guns Port plug guns Schlumberger Oilfield Review Revision 2: 2001 S T I M U L AT I O N b. Check the acid and additives supplied on-site are as specified. Batch mix the treatment; do not allow it to stand unagitated as chemicals may separate. Check everything is mixed as per design specifications. c. Check that all pipework is clean. Pipework previously used for a cement job is not suitable (acid + cement reduces acid strength and potentially damaging products may form). If coiled tubing is to be used, check its age, its previous history and its present day cleanliness. d. Check maximum wellhead pressure for the job: be it the formation fracture pressure or the wellhead rating that dictates e. Collect return acid samples; look for emulsions, sludge; measure iron concentration to check that sufficient sequestering agent was used. f. Throughout the acid job, monitor and record all the parameters accurately. The results of the job (pre-job vs post-job rates, and a subsequent well test) should be carefully matched with the expectations of the treatment to evaluate its effectiveness. All the above precautions must be borne in mind when contemplating, planning or executing an acid job. • • • • • Think carefully about how acid is going to improve the permeability/reduce the skin Experiment with cores where possible Consider possible damage from acidisation. Take precautions to minimise Supervise/quality control job carefully Evaluate job as critically as possible to improve future acidisations One great advantage that acid stimulations have over fracture stimulations is cost. Typically in the North Sea: • • An average figure for an acid job might be $100,000 A frac will cost nearer $600,000. (counting service company costs only) On land in the USA for instance, the frac will probably be much cheaper than $600,000, but will still be more expensive than the acid job. Microbes as an Aid to Well Production As oilfield hydrocarbons were originally formed by microbial action millions of years ago, it should be possible to use microbes again to change the properties of reservoir fluids in such a way as to improve oil production and recovery. The most common approach considered is to pump down, into the reservoir, microbes, which will then feed on the crude oil and multiply, in the process breaking down long-chain hydrocarbons into shorter chains. Thereby, lowering the viscosity of the crude oil, increasing its mobility and reducing any tendency to Revision 2: 2001 139 WELL PRODUCTIVITY AWARENESS SCHOOL paraffin wax precipitation. In some processes, this same reduction of viscosity is achieved, or aided, by formation of organic solvents by microbial action. Common by-products of this process are surfactants, which reduce the interfacial tension between oil and water, thus improving the oil recovery from water flood projects. Another common by-product is carbon dioxide, which provides a limited amount of energy, gas pressure, to help force the reservoir fluids towards the wellbore. In some projects, Microbial Enhanced Oil Recovery (‘MEOR’), is applied reservoirwide, by pumping the microbes down with injection water on a continuous, or near-continuous, basis. In others, the microbes are squeezed in batches into the reservoir in oil producing wells, typically 3-5 feet into the formation, which, after being left up to two weeks for the microbes to multiply and act on the oil in situ, are flowed back. The resulting modification of the reservoir fluid properties near to the wellbore, gives lower near well-bore pressure losses, lower skin and an improvement in well productivity. After a large initial increase in production, this declines, so treatments are usually repeated every three to six months. A recently reported series of such treatments in four wells in Venezuela, for example, gave a more than doubling in average oil production over approximately half a year of post-treatment production. In addition to Venezuela, field MEOR projects have also been implemented in Australia, China, Rumania, Russia and the USA, with approximately ten thousand wells benefiting from MEOR Worldwide. Indegenous Thermophillic Coccoid Bacteria growing in reservoir core material at 90° In addition to reduction in near well-bore pressure losses, microbial treatments are used for other purposes. For example, some microbes compete with Sulphate reducing bacteria (‘SRB’) for food, and, when introduced into the reservoir, will literally eat the SRBs lunch, resulting in a reduction of the SRB population and hence in the H2S content of the produced oil. This increases the value of the crude oil and reduces corrosion. Sometimes the reduction in wax content is primarily aimed at reducing plugging of flow-lines and well tubing, so as to reduce well maintenance costs. Another application being researched is the creation of biomass in situ, to block-off water producing sands adjacent to the wellbore. Obviously, different microbes are used for different purposes, and it is very important that laboratory tests with the actual crude oil are made before any field trials are conducted. Though the use of microbes to improve oil production was first proposed as long ago as 1926, field applications remain limited outside the USA, many projects being little more than field trials. MEOR is however, the subject of numerous joint oil industries, governmental and academic research programmes, particularly in the USA, Norway, Australia and the UK. Use of microbes to improve oil production holds much promise for the future. 140 Revision 2: 2001 S T I M U L AT I O N Hydraulic Fracturing Basics of Fracturing width Propped hydraulic fracturing is of major importance to BPX and many other oil companies world-wide. Successful fracture treatments may increase the productivity of a well up to 400% relative to a zero skin well. This may result in substantial capex length savings (less wells per field necessary), or it may extend the economic life of a field. height A frac may be necessary to break through s e v e re formation damage (that has not One wing of a fracture in a vertical well. The wellbore is lined with casing and the frac been penetrated by the perforations), or it initiated through perforations. may be desirable to increase the productivity of a well in a very low permeability reservoir. In some cases – Ravenspurn, for instance – a field would not be developed but for the success of frac treatments. However fracs are generally expensive operations and therefore their economic benefit must be evaluated carefully. The first deliberate hydraulic fracture treatment was carried out in the USA in the 1920’s. However, it was not until 1949 that Halliburton carried out the first successful, commercial frac treatments. By 1955 more than 3000 wells a month were being treated; and by 1968 more than half a million jobs had been performed. Advances in Hydraulic Fracturing Applications 1946 - Marginal well stimulation technique 1955 - More than 3000 wells/month treated Hugoton, Kansas Late 60's - Radio-active liquid waste disposal Oak Ridge, Tennesee Mid 70's - Tight gas massive hydraulic fracturing Rocky Mountains, Colorado Late 70's - Carbonate reservoir fracturing North Sea, Netherlands 1980 - Blow-out kill from a well nearby 1982 - Medium and high permeability reservoirs Kuparuk, Alaska 1982 - Coal seam methane drainage San Juan Basin, Colorado 1984 - Offshore high rate gas wells Ravenspurn, UK North Sea 1985 - Frac pack for sand control West Sak, Alaska 1987 - Horizontal well stimulation Sprayberry, Texas 1989-91 - Drilling cuttings disposal 1991 - Frac pack for sand control Alaska, Gulf of Mexico, North Sea Revision 2: 2001 141 WELL PRODUCTIVITY AWARENESS SCHOOL To Frac or Not to Frac? Determine if the well is providing the maximum benefit, indicated by return on investment and net present value. Evaluate permeability and skin (near well damage) from well test. Determine benefit using NODAL analysis for various combinations of: • Recompletions (tubing size, perforations, surface equipment, artificial lift) and • Matrix treatments (different materials and sizes) or • Fracture treatments (different material and sizes) Maximum benefit achieved for recompletions only? Yes Perform recompletion. No Yes Perform matrix treatment. Maximum benefit achieved after matrix treatment only? No Is maximum benefit achieved after matrix treatment with recompletion? Yes Perform recompletion. No Yes Perform fracture treatment. Is maximum benefit achieved after fracturing only? No Is maximum benefit achieved after fracturing with recompletion? Yes Perform recompletion No Fracturing not needed. The science of fracturing is a huge subject. Only the basics of the process can be dealt with here. Hydraulic fracturing is the pumping of fluids at rates and pressures sufficient to break the rock, ideally forming a fracture with two wings of equal length on opposite sides of the borehole. If pumping were stopped after the fracture was created, the fluids would gradually leak off into the formation; pressure inside the fracture would fall and the fracture would close, generating no additional conductivity. To preserve a fracture once it has been opened, either acid is used to etch the faces of the fracture (an acid-frac in carbonate) to prevent them from fitting closely together, or in a sandstone the fracture is packed with proppant to hold it open. 142 Revision 2: 2001 S T I M U L AT I O N To Create a Propped Frac • • Perforate well - efficiently • • Pump proppant to hold the frac open Pump crosslinked gel under pressure to initiate and propagate a fracture. Gel used to minimise leak-off The gel must have a 'breaker' to allow the fluid to revert to a water-like consistency for ease of flow-back once the frac is in place Conventional hydraulically induced fractures are almost planar, with widths typically of 1/10th to 1/4 inch, even though lengths and heights may grow to several hundred feet. A fracture will always tend to open against the line of least resistance; so the plane of the fracture will be perpendicular to the minimum principal stress, irrespective of the deviation of the well. Sv St Sr Vertical Stress Min horiz. Max stress horiz. stress Stresses in the earth act in three principal directions, one vertical, and two horizontal, a maximum and a minimum. At the borehole well, these are vertical, Sv, radial, Sr, and tangential, S t. Vertical stress induced by overburden usually exceeds the two horizontal components. This means a fracture will have the least resistance to opening along a plane normal to the smallest principal stress. Because this stress is horizontal, the fracture will orient vertically. In areas of active thrusting, and in some shallow wells, a horizontal stress may exceed overburden and the fracture will form horizontally. Regional tectonic forces determine the azimuthal orientation of the least principal stresses and thus of the fracture wings. Schlumberger Oilfield Review In principle a frac treatment, usually a combination of stages of viscous crosslinked polymer gels, is initiated at pressures exceeding the formation breakdown pressure . Once the frac has been initiated, it is propagated at a slightly lower pressure. If the fracture initiates in the middle of a thick uniformly stressed body of rock, it will normally grow uniformly in all directions within the plane, resulting in a coin-shaped shaped fracture. However, if a fracture initiates in a lower stressed formation, bounded above and below by higher stressed rocks, as is normally the case of a sandstone surrounded by shales, then the vertical growth of the fracture will be restricted by the shales. Revision 2: 2001 143 WELL PRODUCTIVITY AWARENESS SCHOOL Frac being pumped Shale layer restricting vertical growth of fracture Fracture Perforations Frac continues to grow downwards Wing of Fracture BOUNDARY AFFECTING FRAC GROWTH As a fracture opens, the fluid begins to leak-off into the formation along the frac, driven by the difference of the fluid pressure in the fracture and the pore pressure in the reservoir. As the fracture area increases, the rate of leak-off from the fracture increases, and so the rate of fracture propagation falls. Ultimately a point of diminishing returns is reached, when the rate of creation of additional fracture area by continued pumping is very low. Often a ‘Minifrac ’ or ‘Datafrac ’ is pumped - without proppant - (and the pressure decline monitored) prior to the main job, to check the design parameters used in job planning. The on-site measurements may modify the predictions made by various computer simulations; which use historical data and rock properties taken from cores and mechanical properties logs to compute estimates of fracture lengths, pressures etc. The frac fluid is formulated such that it will lose its viscosity (at reservoir conditions) a few hours after the frac is in place. Frequently a 'breaker ' is included in a frac fluid, so that it loses its viscosity with time. Thus the frac fluid will flow back through the fracture and not remain in the formation or the frac. If fluid loss agents are included in the fluid formulation, to assist in the building of a filter cake to reduce leak-off, then these too must be removed during the clean up, by temperature or dissolution in the produced fluid. The aim of the propped frac is to open a channel between the reservoir and the wellbore; effectively increasing the drainage radius of the well. The frac will deliver the hydrocarbons to the wellbore, but the matrix of the rock must still deliver the hydrocarbons to the frac face. The pressure drop within the frac must be low to encourage the passage of hydrocarbons: in other words there must be good fracture conductivity. 144 Revision 2: 2001 S T I M U L AT I O N Treatment Types a) Acid Fracs This method of stimulation has already been mentioned in the “Treatment Types” Section above, as it crosses the boundary between an acid treatment and a fracture treatment. PROPPED FRACS To prevent closure, hydraulic fracture is propped open by pumping a slurry of sand. At greater depths high strength proppant is used. • Substantially increases production from low permeability formations (less than 10mD). • Bypasses skin damage over a wide range of permeabilities. • Fractures can grow out of zone resulting in water and unwanted gas production. Fracture has grown into water zone. ACID FRACS Proppant • Only used in carbonates. • Conductive path along fracture created by acid "etching" fracture walls. • Etched formation must be strong enough to withstand closure forces. HYDRAULIC FRACTURE TREATMENTS Created by pumping above the pressure needed to fracture the rock b) Propped Fracs In sandstones, the faces of the frac cannot be etched with acid, and therefore the frac must be held open with proppant. The amount of proppant pumped is important since it may become partially embedded in the frac face upon closure, and therefore sufficient proppant must be pumped to keep the fracture open and conductive. Proppant can become crushed; therefore care must be taken when estimating the fracture conductivity. The permeabilities of some proppants, as set out in the manufacturers literature, are often optimistic. Revision 2: 2001 145 WELL PRODUCTIVITY AWARENESS SCHOOL Sandstone Embedment Gross Aperture Net Aperture Filter Cake Sandstone FRACTURE CONDUCTIVITY is all important. • Proppant must be strong enough to withstand closure stresses • Proppant must be well rounded and perfectly sized, with no fines/debris that will limit permeability • Proppant must be as large as is practicable • The crosslinked gel used to carry the proppant must be non-damaging and must lose its viscosity (due to a 'breaker') once the proppant is placed • Any additives in the gel must not leave solids in the proppant • All fluids must be scrupulously clean LENGTH OF FRACTURE There is an increasing trend away from an emphasis on very long fractures, to an emphasis on fracture conductivity. LARGE SCALE IDEALISED CROSS-SECTION OF PROPPED FRAC (Viewed from above) Proppant is placed in fractures in slurry form. A stage of clear frac fluid, the ‘pad’, is pumped ahead of the slurry stage to create the correct fracture dimensions. A slurry stage is then pumped to fill that volume. As the slurry moves towards the tip of the fracture it becomes progressively more concentrated as fluid leaks off. The early part of the slurry, which is expected to reach the tip, is usually pumped at low concentration: usually 1 lb of proppant per gallon of frac fluid. If too high a slurry concentration was pumped early on, it could dehydrate and bridge off before reaching the end of the fracture. The slurry concentration is gradually increased as the treatment progresses. CONTROLS ON FRACTURE PERFORMANCE FRACTURE PERFORMANCE DEPENDS ON: ABILITY OF FORMATION TO SUPPLY FLUID TO THE FRACTURE ∝ FRACTURE LENGTH ∗ ROCK PERMEABILITY ABILITY OF THE FRACTURE TO TRANSMIT FLUID TO THE WELL ∝ FRACTURE WIDTH X FRACTURE PERMEABILITY 146 Revision 2: 2001 S T I M U L AT I O N Design of an Ideal Fracture Treatment Improved or expanded stress and modulus data. Test for different fracture model or less length. Obtain stress magnitude and Young's Modulus1 versus depth from logs, cores. Also collect other well and formation information: lithology, nature fracture locations, porosity. Check offset well data. If appropriate fracture geometry model not known, do microfrac (1/3 to 1/ 2 length of actual job, no proppant) to select fracture geometry model (2D, P3D, MLF). Fracture skin or lower fracture conductivity? Select fluids and additives that minimize formation and proppant damage and environmental impact. Different reservoir model permeability? Is reservoir anisotropic? Layered? Stress sensitive? Obtain permeability and reservoir pressure from well test; porosity from logs. If not done earlier, perform microfrac to determine correct model, fluid loss coefficient and treatment efficiency (volume of fluid pumped versus volume of fracture, determined mainly by leakoff). Different fracture geometry model or length? Iteration for revisions Use net present value (NPV) calculation to select proppant, optimize pump schedule and fracture length, and predict production. Finalize pump schedule with PLACEMENT program. The program gives pressure required during job, frac length at end of job and distribution of proppant. Execute job. Do well test and use ZODIAC program to evaluate fracture treatment and reservoir characterisation. No Is well producing as expected? Yes Analyse bottomhole pressure during execution with various fracture models. No Was bottomhole pressure during execution as expected? Yes Fracture treatment design is optimal. 1. Young's Modulus is the ratio of stress (force per unit area) to strain (displacement per unit length). Schlumberger Oilfield Review Revision 2: 2001 147 WELL PRODUCTIVITY AWARENESS SCHOOL Job Description Information Stage Name Pump Fluid Rate Name bbl/min Stage Fluid Proppant Volume Concentration gal lbm/gal Proppant type + Mash Estimated Surface Pressure psi Pad 35 YF140 5,000 0 Slurry 35 YF140 9,000 2 INTERPROP + 20/40 4610 Slurry 35 YF140 14,000 4 INTERPROP + 20/40 3760 Slurry 35 YF140 23,000 6 INTERPROP + 20/40 3080 Slurry 35 YF140 15,000 8 INTERPROP + 20/40 2460 Displ. 35 YF140 13,200 0 A typical pumping schedule for a hydrofrac in a gas well in east Oklahoma, USA. Each unit of fluid that represents a change in proppant concentration or flow rate or both is called a stage; a specific sequences of stages is called a pumping schedule. This is a pumping schedule to produce a 909-foot [277 m] fracture. The pad fractures the rock and helps transport the proppant which holds the fracture open after pressure is released. A major component of fracture design is establishing the volume and chemistry of pad and slurry. Generally, the pad is the largest stage, accounting for 30 to 50% of fluid, and, rarely, up to 70%. Ideally, to optimise the propped fracture length, the pad is completely leaked off at the moment the fracture reaches its intended - 5630 - length. If the pad leaks off too soon, the fracture will be too short; if too late, the fracture is not effectively propped. In this well, five slurry stages with different proppant concentrations and volumes are used, but as many as 17 or 20 slurry stages may be used in large frac jobs. The later slurry stages have higher proppant concentrations than earlier stages because the slurry fluid leaks off as it travels along the fracture. Therefore, a slurry concentration that starts at the wellbore as 2lb of proppant per gallon of fluid [240 kg/m ], may end up as 8 lbm/gal [960 kg/m ] at the end of pumping, and 44 lbm/gal [5270 kg/m ] when the fracture closes. In this job, one proppant size is used (20/40 refers to a standard sieve mesh size that permits passage of a particle with an 6170 average diameter of 0.63 mm [0.025 in.]). A larger proppant is sometimes used near the wellbore to minimise turbulent flow, which would decrease hydrocarbon flow rate. Time for job = 54 mins. Identifying Candidates The productivity increase that may be achieved by fracturing is a function of fracture length, fracture conductivity and fracture/wellbore communication. It is difficult to lay down firm guidelines for the selection of wells, as each field or well should be considered on its individual merits. When planning any frac-job careful consideration must be made of the risk of a frac extending out-of-zone, i.e. below the oil-water contact, or up into a gas cap. There are numerous computer programs to predict the size and shape of a frac; like all programs, if poor data is input, the predictions are not worth much. Ensure that valid data is used to predict the frac. Data for input to the frac program includes: • • • • geological data formation boundaries/layers from logs mechanical properties (from logs, sonic + density) core data – Young’s Modulus – Poisson’s Ratio This data is fed into one of a variety of programs: 148 • 2D – • P3D – Two dimensional • Fracture height input Pseudo three dimensional Fracture height, length and width can all vary somewhat independently Revision 2: 2001 S T I M U L AT I O N • 3D – Three dimensional Fracture height, length and width can all vary independently • Lengthy computation time • More data input required To complicate matters further, the mathematics of the above programs may be based on one of three common models: • Perkins-Kern-Nordgren (PKN) • Khristianovic-Geertsma-de Klerk (KGD) • Radial model The details of the various programs and models are outwith the scope of this book, but suffice to say that if a frac prediction is wrong it can lead to placement problems, where too much proppant is pumped for the size of the fracture; or to production problems when the well doesn’t flow as predicted. The competence of the cement job surrounding the perforations should also be evaluated for the same reason. The perforations themselves need be only 4 spf to 6 spf, and phased at 45 to 60 degrees. The perforation diameter should be at least six times the mean proppant diameter. Wellbore Hydraulic fracture normal to least stress Casing 60° phasing never >30° from fracture Orientation of least horizontal stress Channel to fracture wings Area of flow restriction 0° phasing perforation The importance of shot phase angle to maximizing communication between perforations and stimulated fractures. Studies of fracture and perforation orientations show that for optimum well productivity, the two lie within 30°, preferably 10°. This minimizes fracture initiation pressure and the length of the channel between the perforation and fracture wings, and increases the likelihood the fracture will initiate along a perforation. Perforating guns with small phase angle and high shot density achieve this optimum angle most effectively. The figure shows that a 0° phasing could place the perforation far from the fracture, which initiates along the plane normal to the least stress. But in reality, wells to be fractured are often perforated with guns at 60° phasing or less (dashed lines). This means the perforation is never more than 30° from the fracture. a) Gas Wells All low permeability gas wells should be considered for fracturing; either at the completion stage or later in the life of the field. If the frac is to be carried out at a later date, this should be borne in mind when designing the completion (including the casing design). Revision 2: 2001 149 WELL PRODUCTIVITY AWARENESS SCHOOL For the North Sea, any well with a permeability of less than 200 mD is a definite candidate, although better wells should not be dismissed. The actual distribution of the permeability within the sand body should also be considered b) Oil Wells In general, oil wells require higher permeabilities to produce at commercial rates than do gas wells. It is therefore symptomatic that the benefit of a frac in an oil well is apparently less than in a gas well. The benefits of fracturing are potentially greater if a positive skin is present but fracturing is expensive and other ways of removing near-wellbore damage should be investigated first. c) Conventional and Tip Screen Out Treatments A conventional frac is designed to be long and thin; whereas a tip screen-out (TSO) frac is designed to be short and fat! Proppant Width Length Concentration (inches) (feet) (lb/ft2) Conventional Frac Up to 0.25 750 to 1500 0.5-2.0 0.25 to 1.50 50 to 500 4.0-12.0 Candidates for Conventional Fracs • Low permeability reservoirs Tip Screen-Out Candidates for Tip Screen-Out • Frac past near-wellbore damage • Reservoirs with fines migration problem • Multiple pay zones • Sand Control (frac packs) • Higher permeability reservoirs CONVENTIONAL VS TIP SCREEN-OUT FRACTURES In a low permeability reservoir, the greatest benefit from a frac may be gained by fraccing as deep as is reasonably possible into the formation to increase the drainage area. In a higher permeability reservoir, especially one with significant invasion/formation damage, or one that is ‘soft’ (i.e. the fracture closes around any proppant, which then becomes fully embedded, thus severely diminishing fracture conductivity), it is more beneficial to have a shorter, wider frac: say 1” x 100ft as opposed to 1/4” x 1000ft. Candidates for shorter, wider Tip Screen-Out fracs are: • 150 Reservoirs with significant wellbore damage. Previous matrix treatments have failed, and short, wide fractures are designed to bypass the damage and connect the undamaged reservoir with the wellbore. Revision 2: 2001 S T I M U L AT I O N • Reservoirs with fines migration. A short, wide fracture can alleviate this by reducing pressure losses and the velocities near the wellbore. • Multiple pay zones in laminated sandstone/shale sequences. The thin sand laminae may not communicate sufficiently with the wellbore until a fracture provides a continuous connection to the perforations. Computer modelling should indicate if the sand/shale barriers will hinder the vertical growth of the frac. The opposite wing of the frac has not been drawn, to illustrate the laminated geology Statoil in Gullfaks use this type of fracturing to produce a weak sand-prone reservoir sandwiched between two more competent reservoirs. The competent reservoirs are perforated (the weak sand is not) and a Tip Screen-Out frac is placed to connect up the weak reservoir to the wellbore. The lower velocities through the frac radically diminish the likelihood of sand production. Casing and perforations not illustrated Proppant Laminated pay zone with sand-shale sequences. The sand laminae may be connected to the wellbore by short, wide fractures. Schlumberger Oilfield Review The difference between the two types of propped frac are: • In a conventional frac – ideally – the pad has completely leaked off the moment the fracture has reached its intended length. The slurry stages, with their increasing concentration of proppant, gradually pack off the fracture, and pumping ceases when the pumping pressure begins to increase as the frac becomes full of proppant and ‘screens-out’ at the wellbore. A typical quantity of proppant placed would be less than 2 lb of proppant per square foot of fracture (lbm/ft2). • In a tip screen-out frac, the frac length is much shorter, and the pumping schedule is designed to carry proppant to the tip of the fracture at an early stage, where it packs off and prevents further propagation of the fracture. The slurry continues to be pumped into the frac, and as the pressures rises the frac is forced open and a greater width is packed. The frac may have a proppant concentration greater than 4 lbm/ft2. Most propped fracs will back-produce some of their proppant. Slow bean-up of wells when putting them on production is important. Special proppant knock-out pots will be required between the well and the process facilities. d) Deviated and Horizontal Wells It is recommended that wells (especially ones that are expected to produce at high rates) that are to be fractured be drilled at low deviation angles through the Revision 2: 2001 151 WELL PRODUCTIVITY AWARENESS SCHOOL reservoir. This may mean drilling a S-bend well. However that is not to say that deviated wells must never be fractured. If the orientation of the field of least principle stress is known – from measurements or from the fault pattern – then fracture stimulation my be very advantageous. Frac propagating perpendicular to the plane of the page Jh Minimal Horizontal Stress Good connections between the frac and the wellbore Vertical Well Poor connection between the frac and the wellbore Jh • inefficient frac placement due to pump/pressure losses • inefficient production greater pressure drop in the near-wellbore region Deviated Well SOLUTION: Drill an S-bend well if you need to deviate away from a platform Two scenarios for directing a horizontal wellbore for induced fracturing. If the wellbore is drilled perpendicular to the minimum stress, indicated by the arrow, the fracture will develop parallel to the well (above). If the wellbore is drilled parallel to the minimum stress, the fracture will develop transverse to the well (below). Schlumberger Oilfield Review The reason for preferring fracture candidates to be low deviation is to get the maximum communication between the frac and the wellbore, which may not happen in highly deviated wells where the frac and the wellbore may only cross at one point. Fracture initiation and propagation pressures will be higher due to higher perforation friction losses. 152 Revision 2: 2001 S T I M U L AT I O N The following field example demonstrates these phenomena: 100 This figure shows that the most productive fracs are achieved on vertical or near-vertical wells; and that if a deviated well is to be fractured the best productivity results (in Alaska) will be achieved if the well is in an azimuth of 0-30° from North. 90 80 70 60 50 40 30 20 10 0 0- 20 0-30 20-40 30-60 60-90 40-60 Well deviation Well Azimuth SURVEY OF FRACS ON ALASKAN WELLS e) Water Injectors It is believed that most high rate water injection wells are fractured due to cooling of the rock and lowering of the formation fracture pressure below the injection pressure (termed thermal fractures). Consequently there is rarely much to be gained by propped fracturing injectors - if possible, it would be better and simpler to increase the injection pressure. Formation Damage During Fracturing PREVENT DAMAGE DURING FRAC • All fluids pumped must be compatible – all compatibility notes mentioned under acid apply here • Good quality control of frac fluids • • • – any crosslinked gel MUST break – check breaker in heat bath on site Check proppant for quality and cleanliness Mixwater must be unpolluted and filtered, and inhibited with NaCI or KCI All pipework must be thoroughly cleaned Whether the purpose of a frac be to breach the formation damage around a well or to increase the drainage area of an undamaged well, it is important that the frac fluids do not damage the formation. The choice of fluids for the frac and the subsequent clean up after the frac are critical for the success of the treatment in this area. Some items to be considered are: a. All fluids to be pumped into a well must be compatible with the reservoir fluids and the reservoir rock. If acid is to be pumped, all the precautions set out in the Section entitled ‘Formation Damage During Acidisation’ apply. Revision 2: 2001 153 WELL PRODUCTIVITY AWARENESS SCHOOL b. Good quality control of treating fluids is essential. The failure of the crosslinked fluid to break can result in virtually zero post-frac productivity. 3700 NOTE: The first fracture fluid that the Service Company suggested was tested at Clair reservoir conditions and found to be entirely unsuitable, being very slow to cross-link and showing no “break-back” of viscosity over time whatsoever. By lowering the base gel pH, omitting all gel stabilisers and including a chemical breaker, a fluid was obtained which cross-linked more quickly, gave acceptable working time (fluid able to carry proppant) and broke very cleanly. 21.7 psi/min 3600 Screen out fully developed 3500 Fracture initiated Fracture propagation Addition of proppant Screen out initiated 3400 3300 3.7 psi/min BP Sunbury 3200 0 20 40 Time (mins) 60 80 100 FRAC IN CLAIR FIELD c. The breaker should be checked on-site in a water bath. d. Take frequent samples throughout the job. e. Check proppant for quality and cleanliness. f. Water for mixing gel should be unpolluted and coarsely filtered, and inhibited with KCl. g. All pipework must be clean. The above list is not comprehensive; basically everything must be checked and rechecked to ensure the success of the job. There will not be a second chance. After a propped frac has been placed, precautions must be taken to ensure proper clean out of any proppant left in the wellbore. When a frac string is pulled out, a suitable filtered fluid must be left in the hole, preferably with a degradable LCM component to stop excessive losses into the frac just formed (the same applies during the workover of a fractured well). When a propped-frac well is brought on stream, it should be beaned up slowly to minimise the shock to the pack and thus minimise flow-back of proppant. Likewise, during the life of the well, rate changes should always be made gradually. In a naturally fractured rock it is worth bearing in mind that fluids will be forced into rocks at very high pressures, yet produced back at much lower drawdowns. 154 Revision 2: 2001 S T I M U L AT I O N Thus it may take quite some time to produce back all the fluid. Foam fracs may minimise losses into natural fractures. In a naturally fractured rock the stresses resulting from the main frac treatment may cause movement of the fractures, possibly closing them or creating fines. This mechanical damage will not be easily removed. Frac Evaluation Generally, great care has been taken in the planning of a frac: to get the right size and shape of frac, after evaluating all the available log and core data; and after running numerous computer simulations. However, more often than not very little post-frac evaluation is done. In Ravenspurn South, the BP engineers were able to convince management that an extensive programme of pre- and post-frac production tests and an extensive logging programme were necessary to properly evaluate the planned fracs – and shut-ins for pressure build-ups can be as long as 14 days on these wells. The programme was conducted as planned (over the first six wells) with evaluation of the early fracs leading to changes in the design of later fracs. The refinement of the frac technique allowed the field to be produced through only 21 wells instead of the planned 38; although laterly the recovery is not quite as expected and some new wells may have to be drilled in the future. Acidisation of Undamaged Well Acid Production Rate 10800 bopd Skin = -1.4 Cased and Perforated 16" Perforations, 6 spf, 60 degree No mud damage Acidisation - 2 Feet, 2 x Permeability No Acidisation Damage Fully Completed Vertical Frac of Damaged Well. Tip Screen-Out Frac How fracs are evaluated: • Comparison of pre-frac and post-frac test data, including pressure build-up • Multiple-isotope radioactive logging (isotopes placed in proppant) • Temperature logging Revision 2: 2001 Production Rate 17820 bopd Skin = -4 Cased and Perforated 16" Perforations, 6 spf, 60 degree 24" filtrate invasion 80% permeability reduction non acid-soluble Fully completed Vertical Proppant permeability 872 Darcies Frac gel fully broken 155 WELL PRODUCTIVITY AWARENESS SCHOOL For further reading on the subject of Stimulation the reader is referred to the Schlumberger Oilfield Review, October 1992 and to the SPE Petroleum Engineering Handbook, Chapters 54 and 55. 156 Revision 2: 2001 PRODUCTION RELATED DAMAGE P roduction Related Damage 1 5 8 Precipitation 159 Scale Precipitation During Production a. Calcium Carbonate b. Sulphates c. Scale Prevention 159 160 162 164 Wax Precipitation Asphaltene Precipitation Hydrates Corrosion Hydrogen Sulphide 166 166 166 167 167 Fines Migration 167 Phase-Related Permeability Reduction 168 Condensate Banking Water Coning Gas Breakout Revision 2: 2001 168 169 170 Stress Induced Permeability Change 170 Injection Wells 171 MODULE SUMMARY 172 157 WELL PRODUCTIVITY AWARENESS SCHOOL Production Related Damage Remember: ‘Prevention is Better than Cure’ At the end of this module you should be aware of: • • • • • • • The main causes of damage during well production Why water production reduces productivity How and where different types of scale are formed How to avoid, or overcome scale problems When wax and asphaltenes can cause production difficulties Why fines migration occurs and how to identify it Loss in oil rate that can occur due to production related damage Water production reduces the wellhead flowing pressure - if the water cut is high, the well may not flow naturally. "Wet" Well Production Wells Injection Well A well which does not produce water is less likely to suffer from production related damage. "Dry" Well Production Well Calcium carbonate can form in the near wellbore region due to the pressure drop when the well is producing. If two incompatible waters mix in the wellbore, precipitates like sulphate scale can form. When scale is deposited in the tubing, it will restrict flow. Damage in the near wellbore region, such as scale or drilling damage, gives a higher pressure drop when the well is flowed - this causes more scale deposition and/or water coning. Tubing Scale deposits The main culprit of production related damage is WATER. – – – – – – it is heavier than oil and therefore robs the production systems of energy it is difficult and expensive to dispose of at surface it causes corrosion it causes scale formation it causes hydrates it causes emulsions How to recognise production related damage Production Rate, stb/day 6000 Natural decline due to drop in reservoir pressure - no production related damage. 4000 2000 0 0 1 2 3 Years of Production 4 Production Rate, stb/day 6000 Rapid decline due to production related damage - productivity might be restored by regular stimulation treatments (not always successful, dependent on interval length and cause of damage). 4000 2000 0 0 1 2 3 Years of Production 158 Revision 2: 2001 4 PRODUCTION RELATED DAMAGE Precipitation PRECIPITATION During production, inorganic products (scale) or organic products such as wax and asphaltene may be deposited – in the tubing – in surface facilities – IN THE FORMATION Greatest impairment will be nearest the well – in the perforations Precipitation occurs either : a. b. c. In the formation surrounding the wellbore and in the perforations, reducing the productivity by increasing the pressure losses in the near-wellbore region; In the tubing, affecting the tubing performance by reducing the tubing ID. However, the skin is not affected In surface flowlines and facilities – problematical, but not of such great concern since surface facilities can be more easily cleared/replaced. Scale Precipitation During Production WHAT IS SCALE? ‘Scale’ is any inorganic, solid material that precipitates in the reservoir, wellbore or topsides equipment during oil/gas production or related operations. Calcium Carbonate (Calcite – CaCO 3) Barium Sulphate (Barite – BaSO4 ) Calcium Sulphate (Gypsum – CaSO4 2H2 O) (Anhydrite – CaSO4) Revision 2: 2001 159 WELL PRODUCTIVITY AWARENESS SCHOOL Calcium Sulphate generally tends to form Gypsum below 100°C and Anhydrite above 100°C although these temperatures are not exact, depending also on pressure and water chemistry. Barium and Strontium Sulphate often appear together in scale (e.g. Forties), forming a single mineral with a composition intermediate between BaSO4 and SrSO4. Radioactive elements (primarily Radium226) are also co-precipitated in the crystal lattice making this type of scale slightly radioactive (LSA – Low Specific Activity Scale) and requiring special disposal/handling procedures. Calcium carbonate scales do not exhibit this radioactivity. Scale usually contains impurities, such as iron minerals, wax, asphaltenes etc. How does it form? Scale can precipitate due to: a. A pressure decline which causes a release of CO2 b. A change in pressure or temperature which causes a drop in solubility c. Mixing of two incompatible fluids Once scale has precipitated in the reservoir it reduces the porosity and permeability. Scale in the reservoir occurs close to the well and the permeability reduction caused by scale is manifested in an increasing skin. It is no use producing a well and hoping that scale will not form. A detailed chemical and thermodynamic study is required at the outset to predict scale formation, and thus plans can be made to minimise the cause and the effect. It is better to prevent scale formation than to rely on stimulation. There are now several computer programs available to assist in scale precipitation studies. a) Calcium Carbonate The most common inorganic scale to precipitate in production wells is calcium carbonate, CaCO3. Many rocks contain calcite, consequently the formation brine is saturated with CaCO3 (i.e. the brine cannot dissolve any more calcite). On production, the pressure is reduced around the wellbore and, in many fields (e.g. Prudhoe), gas is allowed to break out from the oil. CO2 dissolved in the formation water then enters the gas phase, this results in precipitation of CaCO3 as indicated by the following equation: Ca++ + 2HCO3 = CaCO3 solid + CO2 gas + H2O Even without a release of CO2, pressure alone causes some loss in solubility. The brine becomes supersaturated which may lead to CaCO3 precipitation. This typically occurs in regions of sudden pressure drop, such as the downstream end of a subsurface safety valve. Such a valve may periodically have to be flushed with HCl acid. 160 Revision 2: 2001 PRODUCTION RELATED DAMAGE CALCIUM CARBONATE SCALE Pressure drops close to the wellbore Problem is selfaggravating. Scale produces an even greater pressure drop, leading to yet more precipitation Formation water is saturated with CaCO3 Ca+++2HCO 3- = CaC03 solid + CO2 gas + H 2O With the reduction in pressure, CO2 breaks out of solution in the formation water and calcium is deposited Limestone/Sandstone with calcite cement In the formation, the pressure reduction during production is greatest immediately adjacent to the production well. Consequently, this is where most of the scale forms. CaCO3 scale in the formation is aggravated by any damage near the wellbore as this reduces the productivity index and increases the pressure drops (for the same production rate). The problem is self-aggravating because the scale deposition causes an additional skin; the well has to be beaned up to maintain production; the drawdown is greater still and more scale is deposited. The loss of production is gradual at first but then accelerates rapidly. The man on the rig has the opportunity to minimise the tendency for a reservoir to form scale: he can drill an undamaged well to minimise that pressure drop and therefore delay the onset of scale precipitation. Fortunately, CaCO3 scale can be removed by hydrochloric (HCl) or acetic acid, or even the benign EDTA chelating chemicals (assuming that all of the scale can be contacted by acid and that both the tubulars and the reservoir are suitable for such treatment). In Prudhoe Bay, BP have found that problems with near-wellbore CaCO3 scale appears to have diminished or stabilised, but scale precipitation some one to two foot from the wellbore may now be the problem, necessitating larger overflushes and/or more retarded acid. If the acid is unable to remove this scale, a small frac treatment (tip screen-out method) may be necessary. Arco Alaska believe that the scale is deposited as much as hundreds of feet from the wellbore. Revision 2: 2001 161 WELL PRODUCTIVITY AWARENESS SCHOOL b) Sulphates a. Barium Sulphate Barytes is barium sulphate. The solubility of BaSO4 is very low. Changes in the pressure or temperature do not result in significant changes to the risk of scale formation. Mixing of incompatible formation and injected waters is the major cause of BaSO4 scale. Seawater and many surface waters contain sulphates which are typically absent in oilfield brines. The formation brines are frequently high in barium and strontium. BARIUM SULPHATE Very low solubility so changes in temperature and pressure do not result in material amounts of precipitation. SULPHATE + BARIUM BEWARE Formation waters are frequently hign in Barium and Strontium Seawater and many surface waters contain sulphates Very insoluble even to aggressive acids. BARIUM SULPHATE Normally has to be drilled out of tubing. If in formation – frac may be necessary b. Calcium Sulphate CaSO4 scale occurs due to mixing of incompatible waters, but the situation is complicated by pressure, temperature and water chemistry. There are several crystal forms of CaSO4, which have different solubilities at given conditions. For instance, low temperatures and pressures promote gypsum (CaCO4.2H2O) formation, while at higher temperature and pressures anhydrite (CaSO4) is more likely to form. Thus, a change in pressure can alter the form most likely to deposit and give an apparent change to calcium sulphate solubility. As with CaCO3 scale, the largest pressure reduction occurs close to the production well (in one report, side wall cores from an open hole production well showed that scale only formed in the last 3/8” of rock). 162 Revision 2: 2001 PRODUCTION RELATED DAMAGE CALCIUM SULPHATE SCALE Production Calcium Sulphate scale occurs by mixing incompatible waters, although pressure and temperature changes can alter the risk of calcium sulphate scale by making a different crystallographic form more likely. Extra pressure drop due to skin? Evaporation of water and mixing of brines can also precipitate CaSO4 DIFFICULT TO REMOVE Cannot be removed by HCI directy. Chemical converters‘ (e.g. caustic) must first be used to change scale to acid soluble form. This is not always effective. Chelating agents such as EDTA can also be used but they are expensive and are slow to react. In all cases, PREVENTION IS BETTER THAN CURE Mixing of formation and injection waters in the liner and tubing invariably causes sulphate scale. This may or may not happen within the formation, but is only of consequence around the near wellbore region where permeability reductions have the greatest affect on fluid flow. Additionally, the scale may form in the perforations. FLUID COMPATIBILITIES Seawater North Sea Miller Formation Water Ula Formation Water Bruce Formation Water Sodium 10890 28100 52582 24570 Calcium 428 615 34676 1410 1366 113 2248 200 462 1630 3509 345 Strontium 8 65 1157 610 Barium 0 770 91 400 Chloride 19699 46050 153030 41660 Sulphate 2962 4 44 13 Bicarbonate 123 1655 134 525 pH 6.5 7.0 6.6 6.3 Concentration in mg/L Magnesium Potassium Note: relative permeabilities of sulphate and barium between seawater and formation water. Revision 2: 2001 163 WELL PRODUCTIVITY AWARENESS SCHOOL Barium sulphate is very insoluble, and is a much more serious problem than calcium carbonate because it is insoluble even in highly aggressive HF/HCl mud acid. It generally has to be drilled out of the tubing/liner (coiled tubing has been used for this purpose in Forties and Magnus). Chelating agents similar to EDTA are available but they are slow and expensive and are ineffective if scale is oil coated. If barium sulphate scale is in the formation, a frac may be necessary. After drilling barium sulphate out of a well, reperforation may well be necessary, either because the existing perforations are scaled up or the drilling process has resulted in formation damage. If the scale can be drilled out on coiled tubing, with the well flowing, there is less likelihood of milled scale entering the perforations. c) Scale Prevention Prevention of scale is better than cure: a. b. c. d. Identify the chemistry of the produced water Attempt to reduce the pressure drops where scale may be a problem. Do not mix incompatible waters. If scale is going to form, inhibit it - especially troublesome barium sulphate. BEWARE: anything you pump into a well is potentially damaging. All injection water must be carefully monitored. Beware of: Injection Water Formation Water Sulphate Seawater/sulphate Barium Barium ions - plugs injection well - in situ plugging away from the wellbore, or in the producing well, when the water breaks through. Dissolved oxygen H2S - forms iron sulphide, very damaging. Corrosion. Toxic. Dissolved oxygen CO2 - carbonates Beware of oxygen scavengers; sulfite and CO2 in scavengers may mix with formation water rich in barium. Even the lubricant used in a gas compressor has been known to damage an injection well. 164 Revision 2: 2001 PRODUCTION RELATED DAMAGE Scale formation can be prevented by the use of scale inhibitors . To protect the near wellbore region, perforations and production tubing these treatments are squeezed into the formation at regular intervals. Then they are produced back with the oil and water. Only small quantities of inhibitor are necessary. They do not change the solubility of the offending scale, but rather interfere with the process of precipitation (i.e. the kinetics) such that scale formation is delayed, or crystal growth is modified so that smaller crystals form which are produced out with the oil rather than deposited in the formation or on the tubing. Offshore the most obvious injection water is of course seawater, but seawater mixes with barium to form insoluble barium sulphate. Some operators desulphonate their injected seawater, but this is very expensive. The Miller Field for instance injects two barrels of seawater for every barrel of oil produced. To desulphonate the seawater would be prohibitively expensive. Thus Miller have developed their own specific inhibitor. The Miller Field will produce 2 tonnes of barium sulphate scale for every 10,000 bbls of oil produced when injection water breakthrough occurs.. How to minimise Production Related Damage Minimise damage whilst drilling the well Complete the well to obtain the lowest possible skin factor Control the producing drawdown Avoid rapid changes in the flowing conditions Scale Inhibitor Squeeze Treatments: are used to minimise downhole scale formation - the scale inhibitor is injected into the formation and during production it is slowly 'returned' in the produced water. Remove the cause. Although very expensive, sulphate can be removed from all injection water to prevent barium sulphate scale. Stage 1: Preflush Stage 2: Pump Scale Inhibitor Inhibitors are injected down the production tubing (beware damage from scale, rust, wax asphaltenes etc. being forced into the formation) or coiled tubing and back into the formation by several feet – at below frac pressure. The inhibitor will be adsorbed onto the sand grains or will reside in the pores of the rock to be gradually depleted by production. The produced oil is evaluated and measurements made to ascertain when the next inhibitor treatment is required. Stage 3: Pump Overflush Stage 4: Shut in Stage 5: Return the well to production - inhibitor is slowly released into the well. Revision 2: 2001 165 WELL PRODUCTIVITY AWARENESS SCHOOL Wax Precipitation WAX PRECIPITATION • Primarily produced in tubing, flowlines and surface facilities due to drop in temperature – but can precipitate in formation where gas breakout causes drop in temperature Wax removed periodically by aromatic solvents and/or hot water washes. Also by wireline cutter. BEWARE of pumping dissolved wax into the formation Wax inhibitor can be pumped down an injection line (if included in completion) Wax deposition occurs primarily due to a drop in temperature, and is most pronounced in tubing, flowlines and surface facilities. Precipitation of wax can however occur in the formation close to production wells, where gas breakout and expansion causes a drop in temperature. In production risers, for instance through permafrost or deep water, wax deposition has also been observed. The tendency for wax precipitation is crude specific. Evaluate live samples from early tests in the laboratory. Wax deposition in the formation is rare and prevention is not normally possible. It could be removed at intervals by injecting aromatic solvents. Heating the solvent can help clear wax out of the tubing, but by the time it reaches the bottom of the well, the temperature has usually equilibrated with the surrounding formation. BEWARE: although wax may not form in the formation, it can be carried into perforations by treatments designed to remove wax from the tubing; or indeed kill fluids, acid, and anything else bullheaded into the formation. Asphaltene Precipitation Asphaltenes are high molecular weight substances held in the oil by various polar compounds. They tend to precipitate out of the crude oil at pressures close to the bubble point. They are specific to oil-type. The problem does not exist in all crudes. The deposition of asphaltene in the formation and the tubing can have a serious effect on well productivity. They are insoluble in non-aromatic solvents and their precipitation cannot easily be inhibited with chemicals. They can be removed slowly with various aromatic solvents. Beware of asphaltene solvents destroying elastomers in packers, seals, and other production equipment. Various asphaltene inhibitors are being developed and should be commercially available in the near future. Hydrates Hydrates are crystalline solid materials comprising water and low molecular weight gases. They are formed at high pressures at low temperatures (but above 0°C). They can block gas lift values and surface chokes. Hydrates can be inhibited by the injection of ethanol or methanol into the gas flow stream. 166 Revision 2: 2001 PRODUCTION RELATED DAMAGE Corrosion Corrosion is known to all of us where water attacks iron resulting in the degradation of the steel. Corrosion inhibitors are put in completion brine and sometimes injected downhole via 1/4” lines. As far as well productivity is concerned two things are important: • no corrosion products should go near the formation • corrosion inhibitors must be tested for formation damage within the reservoir Hydrogen Sulphide Produced water, sulphate reducing bacteria and other circumstances can lead to the production of H2S. This will cause hydrogen-embrittlement of steel apart from the obvious danger to life from poisonous gas. Always consider inhibiting completion brines to minimise the chances of H2S generation. Fines Migration Tiny solid particles occur in the pore spaces of all sandstone formations. Fines are usually identified as any solids that pass through a 400 mesh (37 micron) screen, which is the smallest screen size available. Electron micrographs have revealed the nature of typical fines; clays, quartz, minerals (such as feldspars, muscovite, calcite, barite) and amorphous material. Clays are only a small constituent; quartz and amorphous material make up most of the fines. Fines are loose, not attached to the sandstone grains, and can move freely within the porous matrix. Experiments have shown that fines movement is strongly affected by liquid phases and boundaries. e.g. fines are only thought to move readily when the phase that wets them is flowing. Mixed wettability fines are confined to the oil/water interface. FINES MIGRATION ’Fines‘ are usually identified as any solids that will pass through a 400 mesh (37 micron) screen (the smallest there is). ’Backflushing‘ of the formation may increase production if fines can be dislodged. Revision 2: 2001 Fines are made up of clays, quarts, minerals (feldspars, muscovite, calcite, barite) and amorphous material. Quartz and amorphous make up most of the fines. Bring the well on slowly to minimise the chances of any fines bridging in the pore throats 167 WELL PRODUCTIVITY AWARENESS SCHOOL Why are fines of concern to well productivity? It has been suggested that imposing a high initial drawdown (opening the chokes rapidly) causes formation damage due to fines migration; wells which are completed and brought on-line with minimal pressure surges to the formation should have lower skins. In some cases, large underbalanced perforating may lead to reduced near-wellbore permeability due to fines migration caused by the underbalance surge. Furthermore, in some fields such as Prudhoe Bay, rapid productivity declines are observed over periods of a few months; some of this is attributed to the movement of formation fines during normal production from the well. Fines cause productivity impairment when they bridge across pore throats. Bridging is a result of two things; a) Fines move only when the fluid velocity is sufficiently high to entrain the particles. Thus fines migration only occurs in a cylindrical region of a few feet around the wellbore. b) Mobile fines accumulate, bridging pore throats and impairing productivity, when they are of suitable size. Laboratory tests indicate that changing the flow direction can increase permeability, at least temporarily. This is as a result of fines bridges across pore throats breaking up. Such observations have lead to the technique of backflushing a well, a useful technique for the identification of fines migration. Some Prudhoe Bay wells respond simply to injecting a filtered fluid into the formation for a few hours (below fracture pressure), which breaks up many of the fines bridges. This results in higher flow rates after the treatment, but does not prevent the onset of a further decline as the fines continue to migrate. Phase-Related Permeability Reduction Condensate Banking In a gas well on production, the pressure drop in the near wellbore region may take the reservoir pressure to below the dewpoint. Some of the liquids in the gas then drop out and settle in the pore structure, thus affecting the relative permeability to gas of the near wellbore region The low permeability due to condensate drop-out will itself cause a bigger pressure drop, and thus the problem is self-aggravating. The presence of a condensate bank is difficult to detect. They can be avoided or delayed by minimising the drawdown of the reservoir. Gas fields with high liquid yields and high dewpoint pressures are most prone to this form of damage. 168 Revision 2: 2001 PRODUCTION RELATED DAMAGE Reservoir pressure Gas dewpoint pressure Zone of condensate dropout Distance MECHANISM As near wellbore pressure is reduced during production, dewpoint pressure of gas is reached. Dropout of liquid hydrocardons in near wellbore zone reduces relative permeability to gas. Once formed, condensate bank will itself cause additional pressure drop, and be self aggravating. OCCURRENCE Only a problem in gas reservoirs with significant condensate yield, and relatively high dew point pressure. Difficult mecahanism to diagnose due to fluid sampling problems. IMPACT Possibly serious, but poorly understood CONDENSATE BANKING Hydraulic fracturing of a problem well/field would reduce the drawdown on the reservoir, and this might alleviate the problem. In some cases a condensate bank can be reduced by pumping ‘dry’ gas into the reservoir and producing it back with the vapourised liquids. Water Coning If a reservoir is completed too close to the water contact there is a danger that water will be pulled into the well ahead of the oil, thus forming a cone. Reservoir pressure Aquifer coning to produce near-wellbore water saturation increase Distance WATER CONING Revision 2: 2001 169 WELL PRODUCTIVITY AWARENESS SCHOOL The cone of water will not only reduce the relative permeability to hydrocarbons but it will adversely affect the tubing performance. The impact of this can be very serious on well productivity, and completion strategy should do everything possible to avoid this problem. Gas Breakout If an oil reservoir has a gas cap and it is ‘pulled’ too hard there is a danger of gas coning. This will reduce the permeability of the rock to oil and thus decrease production. Alternatively, if the reservoir pressure falls below bubblepoint, gas will come out of solution and surround the wellbore. This will also reduce the relative permeability to oil and affect the productivity of the well. Reservoir pressure Oil bubble point pressure 1 Increased near-wellbore gas- saturation 2 Downward Coning of pre-existing gas-cap Distance MECHANISM Near wellbore increase in gas saturation may have two causes (see above) OCCURRENCE Easy to predict/diagnose, but difficult to quantify. IMPACT Potentially severe PREVENTION/REMOVAL Minimise production drawdown. GAS BREAKOUT A rising GOR in a well is easy to identify, but the extent of the damage downhole is not. Once again, the preventative measure is to minimise the drawdown on the reservoir. The bubble point of a reservoir is a field-wide pressure and therefore this is more of a field problem than a well problem; however, once again, if a well has to be drawn down by a greater pressure to achieve a certain productivity (because it is damaged) the problem will be exacerbated. Stress Induced Permeability Change As a reservoir is produced and the pressure drops (given no pressure maintenance) the overburden pressure can cause the pores to close up, thus reducing permeability. This effect will be greatest in: a. Overpressured reservoirs – high drawdown b. Fractured reservoirs – fractures may close 170 Revision 2: 2001 PRODUCTION RELATED DAMAGE c. Unconsolidated, mechanically weak reservoirs d. Low permeability (usually gas reservoirs) An example of stress-induced permeability reduction can be found in the Pedernales Field in Venezuela where a reduction in reservoir pressure of about one third of the original pressure led to a permeability reduction of 20%. In some of the Norwegian N. Sea fields the seabed is sinking due to evacuation of the reservoir. The extent of the reservoir permeability reduction is unknown. What is known is that some of the platforms have had to be raised to re-establish their original height above the sea level. Injection Wells Laboratory tests involving the injection of seawater into cores invariably show a loss in permeability with time, as solids in the brine create internal or external filter cakes. Based on the radial flow equation this would result in a significant loss in well injectivity with time. This led to the use of fine filtration equipment for water injection in most BP fields. However, two lines of investigation have shown that fine filtration is unnecessary in the North Sea: 1) Measurements on the quality of water prior to the filters and downhole showed that filtration has no measurable effect on water quality. This is because the quality of North Sea water is very good to start with; solids enter the system after the filters (due to corrosion, system upsets etc.). 2) Hydraulic impedance testing has shown that most of the injectors are thermally fractured. Thermal fracturing caused by cold injection water hitting the reservoir water pressure results in the surface area of formation exposed being much greater than in an unfractured well. This makes it less prone to damage because: a) It takes longer to achieve the same permeability reduction due to a larger area which must be damaged; b) The same permeability reduction causes a smaller pressure loss (because the velocity through the damage is lower). Although thermally fractured wells are more tolerant of damage than unfractured wells, they can be damaged, especially by the injection of lower quality produced water. The damage is partly due to oil carry-over. However in places such as Forties, small calcium carbonate ‘scale’ particles, precipitated from the produced water due to loss of carbon dioxide, are responsible. Revision 2: 2001 171 WELL PRODUCTIVITY AWARENESS SCHOOL 172 Revision 2: 2001 WORKOVERS Wo r k o v e r s Types 174 Workover Practices 176 Well Killing 177 Fluids a Types b Importance of Cleanliness Filtering 178 178 181 Best Practices 182 Water Shut-off Treatments 188 Coil Tubing 190 MODULE SUMMARY 200 a Drilling b Completions c Well Maintenance Revision 2001 174 190 197 199 173 WELL PRODUCTIVITY AWARENESS SCHOOL Workovers At the end of this module you should be aware of: • • • • • The main causes of damage during workovers The different ways to kill a well The reasons for using special filtered brines Why kill pills are sometimes used How to avoid workover damage Types • Workovers should not be the poor relation of the oil industry $$$ They can be very profitable £££ Too often, workovers are thought of the poor relative of oilfield operation. This is a fallacy. The workover of a well is as important as when the well was drilled in the first place. Formation damage and productivity impairment can still occur. A very large proportion of BP’s annual budget is spent on workovers. BP Alaska spends in excess of $200 million per annum in workovers. A workover is an operation upon an existing well – be it an oil or gas well or an injection well – that materially alters the physical condition of that well. Some 40% of the BP Aberdeen ‘drilling’ budget is spent on workovers, as opposed to drilling. It is therefore a significant part of the operation, and a serious potential avenue to cause damage rather than to improve well productivity. There are countless types of workovers: • • • • • • • • • • • • 174 Scale treatment by injection Wax cleanout Recompletion – different configuration or repair of existing design Plugback and sidetrack – Recompletion Drainholes and multi-laterals Reperforation – Change of perforations Acid stimulation Fracture stimulation Deepening of well Water shut-off Gravel pack A combination of the above Revision 2001 WORKOVERS Mechanical Reasons For Workovers Replace Failed Equipment: During production, the well completion is subject to a corrosive and erosive environment - tubing can develop leaks after only a few years. Artificial lift also needs replacing regularly - electric submersible pumps (ESP's) have a typical life of 6 - 18 months, sucker rods about 24 months. Resize Tubing/Add Artificial Lift: As reservoir pressure drops, less energy is available to bring oil and gas to the surface. The situation gets worse as water cut increases with time. In many older wells, the tubing size must be reduced, and/or artificial lift (such as gaslift, ESP's, jet pumps or rod pumps) must be added. Reservoir Reasons For Workovers Gas Oil Cone Channel in cement Cement Channels: Poor liner cementing can leave mud-filled channels around the liner. Water or gas from other intervals can then get into the wellbore, reducing oil production and causing many other problems. Sometimes, mud in channels holds back unwanted gas and water until the well is stimulated with mud acid. 'Remedial' workover operations are needed to cement the channels. Recompleted Well Zonal Isolation: Unwanted water or gas production may need to be shut off. This might be done with cement, a bridge plug or 'straddled' with a piece of tubing and two packers. Recomplete to Produce from Other Horizons: Many fields contain several reservoirs. Older wells may be recompleted to begin production from a new reservoir. Sand Control: Wells which produce from weak sandstones may not require initial sand control, but sanding problems may get worse with time. 'Remedial' sand control may be needed to reduce sand production. Watered out Formation Cement Plug There are countless ways of conducting a workover: WITH RIG INTERVENTION • Full-sized drilling rig • Workover rig • Workover hoist NON RIG INTERVENTION • Slickline • Electric Line • Snubbing unit • Coiled tubing • Pumping (acid and/or frac) Types of Workovers Rig Workovers - The well completion is pulled to perform work such as liner repair, tubing or ESP replacement. A workover rig, drilling rig, or pulling unit is used. Because the tubing is pulled, the well must be killed. Snubbing Unit Workovers - It is possible to pull and run tubing under pressure without killing the well, by using a 'snubbing unit'. This reduces the risk of formation damage, but is much more expensive, and there are limits to the pressures and tubing sizes which can be handled. Through Tubing Workovers - Coiled tubing units allow drilling, under-reaming, cement squeezing, gravel packing and other operations to be done through the production tubing. Often, the work can be done without killing the well, and sometimes it can be performed with the well flowing. Other coiled tubing workovers include running concentric re-completions complete with spoolable gas-lift valves. Revision 2001 175 WELL PRODUCTIVITY AWARENESS SCHOOL Workover Practices The types of workover during the life of a field will change as the field matures. Initially the workovers will tend to be repair jobs on things that went wrong during the initial drilling and completion. Then, the trend will be towards measures to extend the life of a well/field as production problems become more prevalent and various methods of enhanced recovery are attempted. As the wells get older, of course, they are more prone to equipment failure. This section of the book, “Workovers”, may appear thin and perhaps not important; on the contrary: Everything that has been mentioned in previous sections applies to workovers. Many of the techniques describes in the next section also apply to workovers. WELL PRODUCTIVITY IS CRITICAL IN WORKOVERS Plan a Workover Efficiently Data Gather all relevant data - mechanical, geological, reservoir and production. Communication Speak to geoscientists, engineers, rig supervisors, crews, service companies. Keep everyone informed before, during and after the job. Safety Maintain all safety rules. Heighten safety awareness. Equipment Make sure that all equipment is fit for purpose, from the rig down to the smallest piece of kit employed. Anticipate most extreme situations that equipment may be subjected to. Location If offshore - can the platform handle your planned operation? Simultaneous drilling and production? If onshore - does the location need to be prepared to prevent logistical problems? Weather Choose when least weather downtime is likely if possible. Official Documentation Obtain all the necessary consents and permits well in advance. Know your Well Condition Would a wireline survey before the rig arrives tell you something that will change the course of the workover? Timing Make a realistic time estimate. Attempt to anticipate and be prepared for predictable problems. Fluids and Kill Pills Take great care in the area - see notes later in this chapter. WELL PRODUCTIVITY Think Well Productivity throughout the planning and execution of the workover. Do not get so sidetracked by mechanical problems that the perforations and the reservoir get neglected. 176 Revision 2001 WORKOVERS Well Killing Ideally a well need not be killed to carry out a workover. If the original completion string permitted the wellbore below the packer to be isolated with a wireline plug (for instance), then the tubing above the packer could be replaced without disturbing the formation (if tubing above is attached to packer via a seal assembly). This is known as a 'top-hole' workover. Alternatively, coiled tubing or a snubbing unit might be employed to work over a well under pressure. In both these instances, the reservoir would not be open to potential damage by a well killing operation. Milling or scraping activity close to the open perfs will create damaging solids that will enter the open perfs. Avoid such activity close to the perfs if possible – or make sure that perfs are sealed with LCM or a sand plug If possible, circulate to kill the well. Avoid bullheading. If kill pill is pumped, make sure that it is clean and non-damaging. Can it be removed later? Put plug in tailpipe if working above the packer Check the well records to see if any fractures present. What is likely loss rate? What sort of kill pill is best suited to the reservoir, without causing formation damage? However, often a well does have to be killed, and this is where the importance of kill pills is paramount. To kill a well requires that a fluid with a greater hydrostatic head than the reservoir pressure be placed in the well. Since the well has previously been designed to produce, the perforations or the open-hole completion should have permeability, and thus the workover fluid will tend to leak off into the formation. A good workover fluid is clean, filtered and devoid of any solids. It cannot therefore form a filter cake and will leak off at a high rate into the formation. To prevent the loss of fluid into the formation, a kill pill is employed. An ineffective kill pill will not only cause a potential well control problem, but may also cause damage to the perforations and formation by plugging with insoluble solids. A kill pill or any chemical in the workover fluid must flow back after the workover, when the well is put back on production; or it must be able to be Revision 2001 177 WELL PRODUCTIVITY AWARENESS SCHOOL destroyed by hydrocarbon flow or treatment with water or acid. Any foreign solids within the workover fluid are in danger of becoming lodged in the formation. Reservoirs with a wide range of permeability are particularly prone to ineffective clean-up. Where possible the well should not be killed by bullheading the tubing contents into the formation, as all the debris and scale within the tubing will be forced into the formation, to the eternal detriment of the reservoir. If possible, coiled tubing should be used to circulate the tubing contents to kill fluid, and/or to pump the kill pill. One technique in use is to dump sand across the perforations to reduce the loss of fluids. But remember that whatever you use to minimise losses must be removed successfully from the well after the job. Think ahead. Sanding Back Damage can be minimised by ‘sanding back’ above the perforated interval. Sand can be 'dump-bailed', or pumped in gelled water using coiled tubing. The sand-pack allows flow-through, and a kill pill will seal against the sand pack instead of plugging perforation tunnels. This can be especially useful when working over hydraulically fractured wells. Kill pill can be spotted on top of sand to control fluid losses. Frac sand pumped in gelled filtered water. Fluids a) Types The workover fluid and the kill pill must be carefully designed. In the past, too often, workovers have been carried out using a logistically convenient fluid such as lease brine, lease oil, manufactured brines, mixtures of local waters, refined oils or even drilling mud. Unfortunately the quality of such fluids is extremely variable, and may critically affect the effectiveness of the treatment. An ideal kill pill must clean up from the well completely after the workover. Tests must be done with various fluids to check which is suitable for each well/field. The common solids that are used in kill pills, and their respective washing systems are: Workover Fluid Kill Pill Solids Wash System Brine Under-saturated brine Sodium hypochlorite Calcium bromide Hydrochloric acid Diesel or xylene Sodium hypochlorite Hydrochloric acid Brine Brine Brine Brine Sized Salt + + + + Calcium carbonate Oil soluble resin Fine grained cellulose fibres HEC or XC Polymer Although these systems are readily dissolved if the solvent reaches the solid, several problems occur in the field: 178 Revision 2001 WORKOVERS • It is difficult to ensure that all of the perforations are washed – the washing fluid may be lost only to those perforations that are open. • The ‘solids’ in the perforations are actually a mixture of solids and polymers, with the polymers generally coating the solids – this reduces their solubility in the solvent. A mild acid – acetic – may be necessary to destroy the polymer, before (for instance) dilute salt solution removes sized salt. It is much better to use a kill pill that is easy to clean up by producing the well; rather than having to rely on chemical removal. A kill pill is nearly always formation specific; when, for instance, the grain size of the formation has been taken into account, and the temperature of the reservoir. The kill pill must be tested for its suitability and the formula not changed without good reason. In Alaska, for example, they formulate pre-thaw and post-thaw kill pills for use at different times of the year because of the changes in the make-up water that is taken from the sea. As a general rule seawater should not be used as a kill fluid or a workover fluid as sulphates in the seawater can mix with possible barium/strontium in the formation water to form insoluble (pore-blocking) barium/strontium sulphate. Any liquid that is used as a workover fluid should not damage the formation, i.e. if there are water sensitive clays present, a KCl brine will be used in preference to an unsaturated NaCl brine. KILL PILLS MUST BE TESTED There are three things that must be tested for a kill pill: • Does the 'filtrate' damage the formation? (this applies to the workover fluid and to whatever the kill pill is mixed with) • • Will the kill pill prevent losses? What is more important in terms of well productivity, will it come out again? Workover fluids must be tested on representative cores for return permeability . Remember that even a small amount of damage in the near-wellbore region can cause high skins. In some cases it may not be possible to perforate past postworkover skins. The apparatus to determine return permeability is discussed previously in this book, in the section covering drilling muds. For kill pills it is necessary to examine the ‘lift-off’ capability of various pills. Revision 2001 179 WELL PRODUCTIVITY AWARENESS SCHOOL Differential pressure measurement Fluid in/out Gas pressure Fluid reservoir Kill pill placed Step 1 Pressure is applied from above (to simulate hydrostatic) and the solids in the kill pill will be deposited here, and should prevent any further passage of fluid. Losses are stopped. The hole can be kept full with kill weight fluid. Permeameter Core plug (11/ 2" diameter x 3" long) Step 2 Steady pressure is applied from below to simulate drawdown, and production from the well. The pressure and time taken to 'lift-off' the kill pill can be measured. Differential pressure measurement Fluid in/out DESIGN OF KILL PILLS Schematic Diagram of Filter Cake Lift Off Apparatus The type of graph that illustrates the comparison between two kill pills is shown below. 100 Calcium Carbonate 90 80 Sized Salt 70 60 50 In this case, the sized salt kill pill is far more suited to this reservoir. In these conditions it is far easier to remove; it takes only 5 psi to 'lift-off' versus the 90 psi necessary to remove the calcium carbonate pill. 40 30 20 10 0 Time (seconds) COMPARATIVE CLEAN UP OF KILL PILLS 180 Revision 2001 WORKOVERS Note that this apparent success of the sized salt kill pill is specific to that particular recipe of kill pill (e.g. various types and concentrations of polymer, sizes and concentrations of salt, etc.) in the formation tested. It is not sufficient to use a kill pill that worked well in a previous field even if the two fields in question have apparently similar sandstones. There is a possibility to carry out even further testing for kill pills, but with increasing cost. It is possible to create perforations in a block of reservoir, to measure production rates through the perforations, and then to kill them, and finally measure production rates after ‘lifting off’ the kill pills (with or without stimulation). These experiments are very interesting for measuring and observing the dynamics of kill pills, but very few petroleum engineers have 1 metre x 1m x1m blocks of their reservoir to play with! b) Importance of Cleanliness/Filtering All the comments made in Section 4, under Completion Fluids apply to workovers – perhaps even more so. NOT ENOUGH ATTENTION IS PAID TO CLEAN FLUIDS DURING A WORKOVER. The financial success or failure of the workover is dictated by the formation: however mechanically slick the replacement of the old completion for a new one is (for instance) matters not if the permeability has been halved in the meanwhile. • Always check the mixing and delivery methods of any workover fluid. Was the equipment (tanks + lines + pumps) clean? • Beware of finely divided asphalt resins or wax in old lease crud. • Beware of additives in refined diesel. • Beware additives in salt (for free flowing properties, for instance). • Filter the workover fluid Proper filtration minimises damage Formation Damage caused by Solids in Workover Fluids A good filter cake minimises damage This graph shows laboratory testing of different fluids pumped through a core plug. Solids content Revision 2001 181 WELL PRODUCTIVITY AWARENESS SCHOOL Note that in many workovers you are dealing with perforations. If you recall from Section 4, perforations are long and thin, and are easily damaged. If precautions were taken to select the correct guns and the optimum perforating technique back at the time of completion, how foolish it would be to fill up those precious perforations with debris during the workover phase. Such debris might never come out again. If you plug the original perforations, you may have to stimulate or re-perforate; both which could render the workover uneconomic. Whatever debris goes in may not come out. It is far easier to enter than exit. Volume of one perforation, assuming it is a cylinder rather than a cone, is 1.28 cubic inches. or 20.6 cubic centimeters 0.4" 10" If there are 20 ft of perforations at 6 shots/ft the total volume of the perforations is 2472 c.c., about 2.5 litres. NOT a huge volume. This is the total volume of the perforations; but of course the flow will be plugged off if either the mouth is blocked or just the surface area of the perforation is plastered with pipe dope, wax, asphaltene etc. BEWARE. Drawn to half scale It is not only fluids that must be clean. All the previous comments about clean pumps, lines, and tubulars apply here, perhaps more so. Rig drill pipe is generally not very clean, even after surfactants, solvents and other clean-up fluids have been circulated through it. One story tells of an apparently clean 12,000 ft string of 5” drillpipe from an active North Sea rig being cleaned, by hammering it repeatedly to remove internal debris. The rubbish and debris filled seven full sized skips. Imagine some of that entering your well and perforations! Even brand new tubing cannot be trusted: recent tests have shown that as much as 81 lbs/1000 ft of mill scale/corrosion can be removed from new pipe (internal and external). The removal of such debris must be conducted ashore, before the tubulars are sent to the rig. Best Practices In Prudhoe Bay BP studied approximately 300 workovers, carried out over four years. They eliminated wells in which cement squeezes, acid jobs, and additional perforating was performed and came up with 51 suitable candidates to study preworkover and post-workover PI’s. (Reference: ‘Prudhoe Bay Rig Workovers: 182 Revision 2001 WORKOVERS Best Practices for Minimising Productivity Impairment and Formation Damage’, C.G. Dyke and D.A. Crockett. SPE 26042.) They came up with a list of best practices, from which the following list is extracted: (a) Well records should be checked in advance for the presence of whole mud losses during drilling. These losses indicate natural fracture permeability which requires a coarser grade of kill pill during killing. The expected losses in a workover may follow a field-wide pattern. In Prudhoe Bay the losses were estimated using the equation, Loss Rate = (100 + 100 PI) bbls/day. (b) Wells should be killed by circulating to minimise productivity impairment. Prudhoe Bay uses filtered seawater as a workover fluid. This has been checked as non-damaging to the Ivishak formation. Cleanliness of workover fluids is particularly critical when treating perforated completions, as only a relatively small amount of particulate solid is needed to block the perforation tunnels. Bullheading will introduce solids into the perforation tunnels/formation. Low permeability wells are more likely to be damaged by bullheading than are high permeability wells because of the smaller pore throats within these formations. To study the effects of bullheading, BP looked at the damaged caused when bullheading corrosion inhibitor treatments down the tubing (where the inhibitor did not enter the formation). HIGH PI WELLS 1 LOW PI WELLS (10-25 mD permeability) 0 -1 -2 -3 -4 -5 Based on single well test pre and post bullhead Based on two month interval pre and post bullhead -6 -7 -8 DAMAGE INDUCED BY CORROSION BULLHEAD TREATMENTS FOR LOW AND HIGH PI WELLS (c) Downhole operations such as milling and scraping must be conducted as far away as possible from open perforations. Whatever the position of the downhole operation, the losses must be cured before the milling or scraping commences. Workover of a well called Z-18 led to an 88% loss of PI, and the need for additional perforating to restore production. Investigation followed to track down the source of the damage. Revision 2001 183 WELL PRODUCTIVITY AWARENESS SCHOOL Losses at around 200 bbls/day. No kill pills pumped. Packer milled 700 ft above perforations. Loss rate continued at 200 bbls/day. MILL ON PACKER 13147 ft 88% LOSS IN PI DURING WORKOVER PERFS 13845-13928 ft 350 300 MILL ON FISH 13888 ft 250 Milling of fish within the perforated section causes losses to drop to less than 10 bbls/day: the solids are plugging the perforations. 200 150 100 50 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 1718 19 20 2122 2324 25 DAYS FROM START OF WORKOVER EFFECT OF MILLING AT PERFS ON DAILY FLUID LOSS RATE, Z-18 Scraping the casing across or near perforations will have the same effect. CASING SCRAPER If the casing has to be scraped to place a packer FINES IN SUSPENSION a) place the packer well clear of the perforation b) only scrape a minimal area where the packer will sit c) do NOT run the scraper lower PERFORATIONS FINES CAN ENTER PERFORATIONS In any workover operation, beware of circulating debris from the bottom of the well past the perforations especially on fractured wells. JUNK FALLS TO TD NO OBSERVABLE DAMAGE TO PERFORATIONS DAMAGE TO PERFORATIONS IF NOT PREVIOUSLY KILLED BY LCM WORKOVER OPERATIONS CARRIED OUT WITHIN PERFORATIONS CAN CAUSE SUBSTANTIAL DAMAGE 184 Revision 2001 WORKOVERS 250 Drill out cement 200 Workover ends here 150 100 Losses cease indicating that cement has plugged the perforations. Scrape casing at perforations 50 Perforations still open 0 DATE CERTAIN WORKOVER OPERATIONS CAN PLUG UP OPEN PERFORATIONS WITH DEBRIS, D-05 (d) Kill pills may be needed to bring losses down to a controllable level (for well control/safety purposes), but they may also be needed to prevent fines – as generated in ‘c’ above – from entering the perforations/formation. 60 40 PI OF WELLS INCREASES 0.3 1.2 3.1 20 0 4.6 6.4 Perforations protected by kill pill. PI maintained or enhanced -20 -40 -60 Short Term PI Change Long Term PI Change -80 -100 PRODUCTIVITY INDEX CHANGE ON RIG WORKOVER - PERFORATIONS PROTECTED BY LCM PRIOR TO DELETERIOUS DOWNHOLE OPERATIONS Revision 2001 185 WELL PRODUCTIVITY AWARENESS SCHOOL 60 40 PI OF WELLS INCREASES 0.3 0.5 1.1 2.1 3.1 6.1 18.9 20 No kill pills pumped. PI's badly affected. 0 S U R G E -20 -40 -60 A C I D P L U G -80 -100 Short Term PI Change A C I D Long Term PI Change PRODUCTIVITY INDEX CHANGE ON RIG WORKOVER - PERFORATIONS NOT PROTECTED BY LCM PRIOR TO DELETERIOUS DOWNHOLE OPERATIONS 10 PERFS NOT KILLED BY LCM PRIOR TO SCRAPING PERFS KILLED BY LCM 0 -10 -20 -30 Short Term PI Change Long Term PI Change -40 -50 -60 EFFECT OF SCRAPING OR MILLING ADJACENT TO OPEN PERFORATIONS DURING RIG WORKOVERS (e) When selecting a kill pill, conduct careful research on the products and types available. Check that the pill is compatible with all the fluids that will be used prior to the clean-up. A means of actively cleaning up the pill must be devised in case it does not clean up by itself. In Prudhoe Bay ‘Liquid Casing’ is recommended as the kill pill for the lower permeability wells, and a ‘Liquid Casing/OM Seal’ blend is recommended for the higher permeability wells. These kill pills will clean up with backflow; however if a well were not to return to production as anticipated, the kill pill can be degraded with a 2% sodium hypochlorite wash. Clean up of Liquid Casing has been so successful within N. Sea wells that this contingency has yet to be required. 186 Revision 2001 WORKOVERS Note: ‘Liquid Casing’ is a proprietary product of fine grained cellulose fibres. OM seal is the same product, but of a coarser grade. The product manages to form a thin internal filter cake, which effectively prevents further losses. However the cake will easily be produced back and/or can be washed away. Whatever the claims of the manufacturer, the product must be tested with your kill pill formulation and with your core for return permeability and lift off. (f) Low PI wells are more easily damaged than high PI wells. These wells require killing by a particulate kill pill; not to reduce losses to an operationally acceptable level, but to prevent damage. (g) Hydraulically fractured wells are easily damaged: a 40% loss of PI has been recorded. They require a different approach. In Prudhoe Bay a 20/40 carbolite proppant pill is placed across the fractured interval before a coarsely graded LCM pill is pumped on top. (h) Prudhoe Bay have found that XCD polymer is better for well clean-outs than HEC. 10 SIZED BORATE SALTS HEC CELLULOSE FIBRES 5 0 SIZED SODIUM CHLORIDE 4 NO PILLS NO NEAR PERF NEAR PERF NO NEAR PERF NEAR PERF MILLING OR MILLING OR MILLING OR MILLING OR SCRAPING SCRAPING SCRAPING SCRAPING 3 8 -5 12 6 -10 Number denotes number of back analysed in each category -15 -20 3 10 -25 KILL PILLS: SUMMARY OF OVERALL EFFECTIVENESS IN NON-FRACTURED WELLS Revision 2001 187 WELL PRODUCTIVITY AWARENESS SCHOOL Water Shut-Off Treatments WATER is the single most obvious culprit of production-related damage. The science – or art – of water shut-off is included here. Options include: • Bridge plug to isolate part of well. • Cement plug; dump cement in well-bore to shut off bottom perforations. OIL OIL CEMENT PLUG WATER WATER WATER SHUT-OFF ACCOMPLISHED WITH CEMENT PLUG • Cement squeeze; shut off all perforations and selectively re-perforate. • Casing patches. • Micro-cements and equivalents to repair failed cement jobs and near-well fractures. • Near-well permeability blockers; organic/inorganic gels, water-triggered hydrogels, resins, injection of particulates, microbial emulsion formers, precipitation of salts, rigid foams. • Relative permeability modifiers. • Viscous polymers, mobility control foams, in-depth gels. COILED TUBING OIL OIL WATER The impermeable shale barrier is incomplete. A cement plug across the water zone may actually promote water coning. GEL Gel or resin is pumped into the water zone via coiled tubing. Although a c/t packer is used for diversion the treatment may still flow upwards and shut off the oil as well as the water! GEL FLUID PROTECTIVE PRESSURE FLUID OIL WATER PRESSURE FLUID WATER GEL FLUID In this application the gel or resin is prevented from flowing upwards by a protective pressure fluid (diesel or water) being pumped dow the annulus. This application needs careful balancing of pressures and fluid mobilities. WATER SHUT-OFF WHERE CEMENT PLUG IS INSUFFICIENT 188 Revision 2001 WORKOVERS r2 PRESSURE FLUID OIL GELLING FLUID WATER O V E R F L U S H h1 A h2 OIL WATER The gel or resin is pushed away from the wellbore using an overflush. The pressure fluid keeps the gel in the water leg. GEL GEL GEL B Gel block is effectively holding the water back, yet is leaving a large proportion of the perforations open for the flow of oil. WATER BLOCK AWAY FROM THE WELLBORE There are hundreds of different mechanical and chemical methods for water shutoff to choose from. No-one is expert in all methods, and experts tend to be partisan. There is no ‘industry manual’ for process selection and design. There is no cure-all process at present and what is successful in one field may be inappropriate elsewhere. Inappropriate target-process pairings have undoubtedly led to some disappointments in the past. The ‘success’ rate has not been high overall. In particular, the duration of the improvement obtained from small, nearwell treatments is often limited. These operations, which are usually of low cost, often pay back quickly, but the average percentage effect on oil recovery has been small. It has not always been easy to find out what worked and what failed. Operators and technology suppliers have previously been less than open. For example, many thousands of gel-based treatments were carried out in the US in the seventies, but relatively few results have been reported in detail. In part the US anti-trust laws and issues involving the windfall profits tax prevented information exchange. Often service companies and chemical vendors would perform a job, but then never found out from the operator what went right or wrong, or were not permitted to talk about it. Many operators developed in-house technology, patented it, and considered it secret. The patent literature is now immense, particularly for viscous polymers and chemical gels. Probably most of those processes work in the laboratory as claimed, but clear-cut application results are often lacking. It is hard to say whether a process or chemical failed when the shortcoming might be in the target selection or in deployment. A success at least proves the process works under some conditions. This situation is changing. Co-operation between operators in general is increasing in non-strategic areas of this type. Industry technology exchange groups in water shut-off have just been set up in the USA and Europe. This co-operation can already help the participating companies access the right technology for the job, though there is still much to be gained. Revision 2001 189 WELL PRODUCTIVITY AWARENESS SCHOOL There are two areas where the technology of water shut-off has improved dramatically: • powerful, realistic, predictive numerical simulation tools that combine reservoir structure, multiphase fluid flow, well test data, production history, process mechanism and process deployment. • the deployment of treatments using coiled tubing to accurately place water-blocking materials. There are two approaches to evaluating whether or not a water shut-off system will work: • ANALYTICAL APPROACH – Simulation. Expensive and time-consuming and yet still has to be field proven. • EXPERIENCED-BASED APPROACH – Experiment with process and procedures on low cost (disposable) well. This second approach cannot be used on limited expensive high production wells in such areas as N. Sea/Alaska. Of all the methods of water shut-off there is increasing promise in the area of gel-type water blocking. However, for proprietary reasons, few of these chemicals/processes are reported in detail. The difficulty arises when trying to match the success of a particular chemical/process in one area with the potential success in a new area. This is where the analytical approach becomes so important. There are several methods of blocking off the water using gel. Some of these are illustrated on the previous page. Not illustrated is a method of pumping the gel into a reservoir where water has broken through in the high permeability layers. The treatment is pumped, and will naturally flow into the high permeability layers. In the lower permeability layers the gel is prevented from becoming a block because it is removed by adsorption and dispersion. Sometimes ‘cold flushes’ are used to help the self-selective placement of the gels in the high permeability layers. The chemistry of the resin systems, organically cross-linked gels, metal ion cross-linked gels, in situ polymerisation systems, swelling hydrogels and relative permeability modifiers etc. available would fill a book on their own. The mechanical methods would fill another. Suffice to say here, that there are methods that work, but greater industry co-operation is required to establish which system works where, and why. Coiled Tubing a) Drilling The technical feasibility and economic viability of coiled tubing drilling (CTD) has been proven, and the progress of this emerging technology is evident in the growing band of operating companies committing to multiwell CTD campaigns. The first attempts at CTD drilling were in the mid-1970’s but the technique essentially failed because of a lack of understanding of the fatigue damage that results from bending and straightening the tube. By 1991, with better technology 190 Revision 2001 WORKOVERS Re-entry New wells Straight holes Disposable exploration wells Well deepening into new producing zone Lateral holes Horizontal extension into producing zone Original Multiple radial drainholes New Deviated development wells POTENTIAL APPLICATIONS FOR COILED-TUBING DRILLING and larger OD coiled tubing, the technique had been re-introduced. CTD has grown from 4 jobs in 1991 to an estimated 120 in 1994. A standard CT unit has to be adapted for drilling; however this is not a massively onerous task. All CT units already have the equipment to operate under pressure, and can thus be adapted to drill, trip and complete wells in underbalanced New Wells 17 Horizontal Reentries 12 15 Well Deepenings Schlumberger Dowell CT DRILLING JOB DISTRIBUTION AS OF 02/94 Revision 2001 191 WELL PRODUCTIVITY AWARENESS SCHOOL conditions. Typical changes are those to the BOP systems to handle drilling tools/motors, and a modular mud system (incorporating all the methodology necessary to handle mud and kicks as explained in the previous section on slimhole drilling). Union Stripper head 4 1/ 16 in, 10,000 psi blind rams 4 1/ 16 in. 10,000 psi cutter rams Kill line 4 1/ 16 in. 10,000 psi slip rams 4 1/ 16 in. 10,000 psi pipe rams Conventional Coiled Tubing BOP Adapter spool Blind flange Spool Blind flange Spool Return line 7/ 16 in. 5000 annular preventer Return line (for underbalanced drilling). Returning fluid goes through a separator and gas scrubber. Oil is stored, gas is flared 7 1/ 16 in, 5000 blind rams 7 1/ 16 in. 5000 psi pipe rams Extra BOP to handle BHA Kill line Spool Casing bowl * Hole size greater than 4 in POSSIBLE BOP STACK CONFIGURATION FOR COILED TUBING DRILLING Advantages Without a long history of job performance it is difficult to define what all of the advantages of drilling use coiled tubing drilling will be. We can, however, make certain performance claims based on conventional coiled tubing experience: – – – – – shorter trip times less space requirement on location transportability lower costs (specific applications) directional control while underbalanced An important feature of this technique is the ability to drill while underbalanced. Continuous pipe, live snubbing and high pressure wellhead control are the primary systems that make this possible. There are several reasons for drilling underbalanced: – – – – – – – 192 prevent formation damage avoid using costly drilling fluids prevent fluid losses minimise fluid disposal costs improvements in ROP potential for oil production while drilling avoid cost of stimulation Revision 2001 WORKOVERS Note that all trips can be achieved underbalanced, and completions can be run in the same manner. Solids disposal Fluid pumpers Filter skid Flare stack Return line 2" coiled tubing unit Wellhead support CTU control unit Data recording BOP control 21 m DIMENSIONS FOR TYPICAL ONSHORE SITE It is sometimes possible to achieve an underbalanced condition with a single phase liquid. Often, however, the drilling fluid must be gasified. While formation gas or air can be used in this application, nitrogen, because it is an inert gas, is most commonly used. UNDERBALANCED OVERBALANCED Fracture plugging Drilling fines migration Fluid leakoff Filter cake Formation Pressure drop Formation fines production Fluid losses Oil & gas flow Drilling fluid flow Drilling fluid flow Wellbore CIRCULATION DESIGN Proper analysis of the circulating conditions is required to ensure that the underbalanced objective is achieved. The rheological effects of the two-phase fluid, both in the CT string and returning up the annulus, must be understood and interpreted. Pressures must be tracked to assess both the underbalanced condition and the nitrogen volume factor. When using low viscosity drilling fluids the turbulence characteristics and liquid velocity profile must be known to ensure cuttings transport. Revision 2001 GAS LIFTING Two phase annular flow Two phase annular flow with liquid/gas with liquid/gas slippage slippage Nitrogen Nitrogen (lowers density) (lowers density) Drilling fluid Drilling fluid (transports (transports cuttings) cuttings) 193 WELL PRODUCTIVITY AWARENESS SCHOOL HORIZONTAL EXTENSION Distance limited by ability to maintain weight on bit for given Hole and Coiled tubing diameters Coiled tubing Coiled tubing Coiled tubing adapter Coiled tubing adapter Disconnect mechanism (to disconnect coiled tubing if BHA becomes stuck) Disconnect mechanism Drill collars Drill collars Orienting tool Muleshoe sub. Positive displacement mud motors Positive displacement mud motors Adjustable bent housing Extended gauge length fixed cutter bit Angle holding assembly for coiled tubing drilling. Add muleshoe sub. to accommodate survey tool for horizontal applications. Use minimum account of collars for horizontal applications. For vertical applications, collars should provide necessary weight on bit. 194 Short gauge length fixed cutter Angle building assembly for coiled tubing drilling. Revision 2001 WORKOVERS At present, CTD tends to be more costly. The costs should come down as the technique is refined and developed. Offshore, CTD will be quickly competitive because of reduced mobilisation and demobilisation costs – if a derrick set is not already installed on a platform. The greatest disadvantage of CTD is the reliance on slimhole motors. These are both costly and can be unreliable. There is also the productivity issue, as discussed in the previous section on slimhole drilling in general. Coiled tubing drilling has been used in the early stages by Elf in the Paris Basin, and NAM in the Netherlands are experimenting with the technique. The first NAM well was a re-entry drain hole through a milled window. An expensive experimental formate mud was used to drill this well. As seen above, CTD can have problems with milling windows because of insufficient weight on bit. To overcome this one company has developed ‘thrusters’. Such systems are available for hole sizes as small as 37/8”; however the larger casing sizes, 7” and greater, may require larger coiled tubing (greater than 13/4”). Coiled tubing drilling is becoming an important factor in the development of the Arctic. Prudhoe Bay operators are industry leaders in the use of coiled tubing for a wide variety of operations, and are now pressing ahead with CTD. Since a well in the area can cost an average of $2.5 million, and a rig based sidetrack $1.7 million, there is an obvious time and economic advantage if CTD sidetracks can be accomplished for $500,000. Depth limits of coiled tubing drilling are governed more by the size and weight restrictions of the reel trailer used to transport the coiled tubing than by the strength of the coiled tube itself. The larger the coiled tubing diameter the shorter the length of coiled tubing that can be transported legally on public roads. Developments are underway to produce a reliable connector to join together two reels of coiled tubing for drilling purposes. The life of a coiled tube is a critical factor in this technique. Coiled tubing drilling subjects a tube to far greater stresses than normal cased hole operations. The life of coiled tubing used in drilling service can be maximised by: • Ensuring that the coil is never used to pump corrosive chemicals • Minimising solids in the mud. • Minimising the number of times that a given section of coil is run over the guide arch and injector head. • Designing BHA's to minimise the weight that must be slacked off on the coil to achieve acceptable penetration rates. • Never 'stacking' the weight of the coil on the bit. In CTD, PDC bits are applicable for use in medium to soft formations. TSD (thermally stable diamond) or natural diamond bits are required for hard formations. Core barrels developed in the mining and the engineering geology (site investigations) industries can be adapted for coring with coiled tubing. Revision 2001 195 WELL PRODUCTIVITY AWARENESS SCHOOL Wellbore hydraulics Cuttings transport is especially important because unlike conventional drilling operations it is not possible to rotate the coiled tubing and therefore the build-up of a cuttings bed on the low side of the hole must be avoided. Beware fatigue in coiled tubing Coiled tubing connectors needed for deep wells Lift limitation on offshore cranes Conventional coiled tubing BOP Extra BOP for drilling tools Special muds may be required e.g. formates Depth limited by lock-up Orienting Tool No rotation beware of cuttings build-up CT Pull or Pressure Release, flapper valves, CT connector 3" OD Monel with Slim 1MWD or WL steering tool 2 7/8" to 3 1/2" OD Downhole Motor with bent housing CONSIDERATIONS FOR COILED TUBING DRILLING The avoidance of cuttings beds is most easily achieved through ‘turbulent’ flow methods. The use of computer models becomes essential in order to ensure the necessary liquid phase velocities in nitrified fluid dilling operations NON-TURBULENT CUTTINGS TRANSPORT Non-newtonian viscous fluid Cuttings Coiled tubing TURBULENT CUTTINGS TRANSPORT Newtonian fluid Cuttings Flow in turbulence Coiled tubing Cuttings bed 196 Revision 2001 WORKOVERS Data Telemetry The use of coiled tubing with logging cable installed inside the tubing bore was pioneered by Nowsco in 1985 and has been in regular service with conventional CT units for logging horizontal wells since the late 1980’s. The availability and practicality of hardwired communication methods permits the use of traditional, reliable steering tools regardless of fluid mixtures being pumped through the coiled tubing. This is particularly important for underbalanced drilling operations where the use of nitrified fluid is required. (Conventional pressure pulse MWD systems do not work in compressible fluid systems.) Coiled tubing Flow Armour braid Multiple conductors Longest Section Drilled with Coiled Tubing As of March 1993 this accolade goes to Dowell Schlumberger drilling for Elf in the Paris Basin. D/S-Elf drilled 4182’ of 37/8" hole. b) Completions The use of coiled tubing in the oilfield is perhaps one of the fastest developing technologies. Traditionally CT has only been used for nitrogen lift to kick-off wells, for conveying fluids (e.g. acid) to the perforations to obviate bull heading or for fishing inside completions. Nowadays CT is used in many more applications. For instance, coiled tubing re-completions have evolved from mule shoes on the end of velocity strings to: • • • • • • • Revision 2001 pump-through shearable plugs seal assemblies locator subs side-pocket gas lift mandrels non-upset reelable gas-lift valves jet pump equipment and landing nipples surface controlled sub-surface safety valves 197 WELL PRODUCTIVITY AWARENESS SCHOOL Safety valve hanging inserts Safety valve landing nipple – Coiled tubing hung off in the nipple profile of the sub-surface safety valve. An insert SSSV was installed that utilised the existing control line. Coiled tubing connector 2 7/8" coiled tubing completion – 6136 ft of coiled tubing installed. – tubing/tubing connectors used to join sectors of coiled tubing to make full string length. Temporary formation isolation packer – in this particular completion the permanent packer set early, which necessitated the setting of a temporary formation isolation packer above. – a velocity string is installed in the later life of the field when the lower production rates dictate a smaller tubing size. Permanent packer (coiled tubing conveyed) 2 7/8" coiled tubing velocity string This operation was conducted on a platform. No lift exceeded 16 tons. The reel was shipped in three 2500 ft lengths. Operating time for an installation such as this is five days and could save up to 50% of the cost of a conventional workover. Five wells were completed in this manner. Similar completions are run in Alaska. In the USA, Nowcam have installed a 20,500 ft 11/4" coiled tubing completion. EXAMPLE OF NOVEL COILED TUBING COMPLETION This completion was installed by Nowsco and Otis in the Shell Leman Field in the Southern North Sea. Manufacturers are developing more packers that can be set on coiled tubing. These packers have to made up onto the CT without any rotation. In Prudhoe Bay spoolable gas-lift valves were factory installed in a 23/8" reel of coiled tubing and successfully run in a well. The downside of having to pull a production string to change gas-lift valves is somewhat offset by the ease of pulling continuous tubing. Coiled tubing re-completion options will be nearly complete when downhole control lines can be designed and incorporated in live installation applications. Control lines are now available installed in coiled tubing, but they are not attached to the coiled tubing. 198 Revision 2001 WORKOVERS At present, coiled tubing used for completions is not available in the corrosion resistant alloys that are necessary in many corrosive environments. This is expected to change with time as coiled tubing completions gain acceptability. c) Well Maintenance Reservoir monitoring is a critical factor in management of reserves and maximising of productivity. With the advent of high-angle and horizontal wells, such operations have moved from wireline to coiled tubing conveyed. Coiled tubing can be used to run memory gauges into horizontal wells, or indeed memory PLT’s. If the operator is prepared to expend the extra dollars, real-time PLT’s can be run on ‘stiff’ coiled tubing, which has an electric line inside the tubing. ADVANTAGES AND DISADVANTAGES OF CTD COILED TUBING DRILLING APPLICATIONS Re-Entry CT can re-enter existing wells, set a whipstock, mill a window in the existing casing or liner, and drill into the reservoir (usually horizontal, although several have been vertical). Drainholes deeper than 1,400 ft have been drilled. Multiple drainholes extended from a single well bore are under consideration. Combination Drilling Conventional rotary drilling equipment is used to drill upper zones and set casing. The zone(s) of interest then are drilled using CTD techniques in underbalanced conditions. The capability of drilling multiple deviated well bores with minimal formation damage will improve production potential for such wells. The overall economics of single well completions and field development using this techniques is attracting much attention. Disposable Exploration And Observation Wells Inexpensive small holes are drilled to obtain formation or reservoir data for exploration or delineation. Typically, these wells are plugged and abandoned when sufficient data has been acquired to monitor reservoir parameters during subsequent production. Production And Injection Wells Under the right reservoir and production conditions, a small hole is drilled and a CT string cemented in place to provide a small diameter, inexpensive well for production or injection. Underbalanced drilling and improved well control • Full pressure control possible throughout drilling operations. • Underbalanced tripping, drilling, and completion reduces formation damage and permits faster penetration with reduced risk of differential sticking. Continuous drillstring • Allows continuous circulation while tripping. • Eliminates joint related problems and allows faster tripping. • No pipe handling, which improves safety and reduces noise. • Reduced environmental impact. No spillage at joints. • Simplified automation, reduced manpower. Compact unit and equipment configuration • Reduced drill site size and associated • Reduced mobilisation and demobilisation costs. costs. Wireline inside the CT drillstring • Allows highspeed telemetry for measurement and logging while drilling (MWD, LWD). • CT protects wireline and simplifies operations through simultaneous spooling of tubing and wireline. • Electrically operated directional control is possible. Drillstring cannot be rotated • Downhole motors required, even for vertical wells. • An orienting tool is required for steering. • Higher friction with the borehole wall. Limited to slimhole applications • Largest hole to date is 6 1/4 in., larger holes technically are feasible. • Small hole size limits the number of casing strings and liners that can be run. Wireline inside the CT drillstring • Fatigued or damaged sections of CT cannot be removed from the drillstring. New technique • Currently in the learning curve. • Workover rig may be required to pull existing completion or run large casing/liners. Revision 2001 199 WELL PRODUCTIVITY AWARENESS SCHOOL 200 Revision 2001 S U M M A RY Summary Revision 2: 2001 202 Where Do We Go From Here? 202 Communication 203 201 WELL PRODUCTIVITY AWARENESS SCHOOL Summary Where Do We Go From Here? There is only one way to go - FORWARDS! EVERYONE must take responsibility. THINK PRODUCTIVITY By now you should have a fair understanding of the myriad of mechanisms that cause formation damage. You should know most of the factors that affect well productivity. What can you do to make things better? This book cannot tell you, the individual, what specifically you can do. You know your job and your part of the operation. It is up to you to go back to the office or the field and think where this new or improved knowledge may best be deployed. This school should have made you aware of the problems, and has given you some of the solutions. You can go out and apply and develop those solutions. When you are involved in any operation, remember the old cliché, ‘PREVENTION IS BETTER THAN CURE’ . Whenever you are planning a well, a workover, or a well servicing operation, think in terms of the life of the well and not just the immediate future. What will be the consequences of your actions - this year, next year, and in several years time? BUT WHERE DO YOU GO FROM HERE? Remember that Awareness is all important • Take an interest in well productivity • Think before you act • Try and improve your operation 202 Revision 2: 2001 S U M M A RY When you are on site, think of the consequences of all your actions; not just in the immediate future but in the years ahead: a short cut to save time and money now could cost dearly in future production and revenue. Communication BREAK DOWN THE BARRIERS Even if you have inwardly digested everything taught in this school, you alone cannot be totally effective in your quest for zero formation damage and maximum well productivity. You must communicate with others and they with you. For instance, you must involve the operator geoscientists and engineers when planning your well or well management programme; they may have information on the geology of the particular reservoir that will assist you to do your job better. The engineer in the office must liaise better with the personnel on the rig; everyone has a contribution to make towards the goal. The danger is of certain people working in isolation, and ignoring the needs of others: the drillers may want oil based mud to prevent stuck pipe and to get the hole down quicker, whereas the reservoir engineer may not want certain surfactants in the formation. Discuss it; reach a compromise, or implement a change of plan. The office-based personnel may only allow one day for clean-up of an uncemented well; the rigbased personnel may well have more experience and know that this will probably take far longer. Discuss it; set better criteria or adopt better methodology or chemicals etc. etc. Revision 2: 2001 203 WELL PRODUCTIVITY AWARENESS SCHOOL THE DANGERS OF WORKING IN ISOLATION 204 Revision 2: 2001 S U M M A RY 'TEAMWORK' - REMOVE THE BARRIERS Pull together to improve well productivity Revision 2: 2001 205 WELL PRODUCTIVITY AWARENESS SCHOOL 206 Revision 2: 2001 G L O S S A RY Glossary Acidisation The use of acid to stimulate wells. Anisotropy Property of having different physical properties when measured in different directions. Aquifer The body of water below an oil/gas reservoir. If a reservoir has a good water-drive, it means that the aquifer if limitless and can maintain the pressure in the reservoir as oil/gas is removed. In multi-faulted reservoirs the aquifer may be compartmentalised and it cannot maintain the reservoir pressure. Water injection into the aquifer assists in maintaining reservoir pressure. Barefoot An open hole completion - no casing or liner installed. Big Hole Charges Creates a big, shallow perforation with a large entry hole for gravel pack operations. Breaker A chemical added to a viscous solution that will ‘break’ (reduce) the viscosity with time and/or temperature. Cap Rock An impermeable rock directly above a reservoir which traps hydrocarbons in the reservoir. Capex Capital expenditure. A term used in economics to differentiate between fixed upfront expenditure and operating expenditure. In normal tax regimes Capex cannot be written off immediately against the project in calculating profits before taxation. Cash Flow A financial expression of the cash flowing through a business with time. Chert Cryptocrystalline silica (structure is so small that it cannot be seen even under a microscope). Very hard rock. Clastic Sedimentary rock made up from fragments of silica laid down mechanically by water or wind. Revision 1: January 1995 207 WELL PRODUCTIVITY AWARENESS SCHOOL 208 Completion Fluids Salt solutions, often filtered, which must be non-damaging. Coning The phenomenon of inducing gas or water to move into a wellbore due to high drawdown. Crushed Zone A small zone around perforation where rock has been deformed. Data Frac A ‘small’ frac conducted before main treatment providing data which is used to ‘fine tune’ main treatment. Debris Small flakes of material formed when perforating charge disintegrates. Deferred Production Oil or gas production that is delayed due to formation damage and/or well productivity problems. The oil/gas is deferred to the end of field life and therefore has a lower value in NPV terms (unless the oil/gas price has soared in the interim). Discounting See Net Present Value. Diversion A technique to ensure treatment of multiple zones. Drainage Radius The area around a well from which a well drains oil/gas. The closer that wells are means the smaller the drainage radius of each well. Drawdown The pressure difference between well and reservoir which causes well to flow. Feldspar Silicate material. Pure silica is SiO2, but feldspars also contain magnesium, aluminium and other elements. Filter Cake A thin layer of material deposited from the drilling fluid onto and into the surface of the wellbore which controls fluid loss to formation. Fines Migration Effect of inducing the movement of small particles through the reservoir which may plug the near wellbore area and reduce oil/gas rate. Revision 1: January 1995 G L O S S A RY Flexing Technique of applying pressure to tubing to get it to “balloon”, and thus dislodge corrosion and/or scale from the walls of the tubulars. The dislodged debris must then be circulated out of the hole, and must not enter the perforations/formation. Flexing is often done on a frac workstring that will be subjected to high pressures. Flow Efficiency The ratio of low rate with actual skin/flow rate with zero skin. Fluid Loss (Invasion) The rate of loss of fluid from wellbore to formation. Formation Damage A reduction in permeability around the wellbore due to drilling/completion/ production action. Frac Pack A combination of hydraulic fracturing and gravel packing to prevent sand production while maximising well productivity. Fracture Conductivity A measure of the ability of a fracture to permit flow of oil/gas. Gravel Pack A means of preventing sand production into wellbore. Heterogeneous A rock which displays differences in texture which give differences in porosity and permeability. Hydraulic Fracturing Deliberate fracturing or rock using viscous gels to improve well productivity. Microcrystalline Very fine crystalline structure; not visible to the naked eye, but can be seen under the microscope. Matrix The actual body of a rock, as opposed to the pore space. A matrix acidisation is one that affects the whole rock as opposed to just the perforations (an acid wash). Net Present Value (NPV) A method of expressing the time-value of money by discounting all monies back to a fixed point at the beginning of the project. An NPV forecast requires a ‘discount rate’ to express the time-value of money. The discount rate is normally 10% or 15%. Revision 1: January 1995 209 WELL PRODUCTIVITY AWARENESS SCHOOL Opex Operating expenditure. A term used in economics to define monies spent to operate a project on a day-to-day basis (e.g. personnel, consumables, power etc.). Operating expenditure can immediately be written off against income when calculating pre-tax profits. Overbalance The amount of pressure in excess of hydrostatic pressure exerted by the mud on the formation. P and A Plugged and Abandoned. When a well is ‘dry’ or some mechanical problem prevents its use as a production well. In the past, most exploration wells were ‘P and A’d’ but many are now kept as future producers. Perforation The link between reservoir and wellbore. Perforation Plugging The blocking of perforations by any material introduced from well/reservoir. Perforation Skin Mechanical skin created by poor perforation design. Permeability A measure of the ability of fluids to flow through a rock. pH Hydrogen ion potential. A measure of the acidity of a solution. 5 6 7 8 9 210 = = = = = more acidic acid neutral alkaline more alkaline Pickling Technique of circulating dilute acid around the tubulars that are to be used for an acid job. The acid would loosen and remove any scale or rust products. Care must be taken that these are circulated out of the hole, and that they do not enter the perforation/formation. Plateau The production level at which a field is produced. During the plateau period the production from the field is potentially higher if wells are beaned up. After a certain time (usually years) a field will come ‘off plateau’ and production will decline. Damaged wells will come ‘off plateau’ sooner than wells drilled without formation damage or completion skins. Revision 1: January 1995 G L O S S A RY Pore Throat The connections between the pore spaces. Porosity (Pore Space) The percentage of void space in rock where fluids are stored, expressed as a percentage. Proppant Sand, ceramic beads or sintered bauxite used to keep open a hydraulic fracture. psia Pounds per square inch - atmosphere. This differentiates a gauge pressure measurement from an absolute pressure measurement. Atmospheric pressure is 14.74 psi or 1 bar, yet a gauge at surface will read 0 psi. Radial Flow A description of how fluids flow from the reservoir to the wellbore. Relative Permeability A comparative measure of the flow of oil in the presence of water or gas. Reservoir A rock which contains oil/or gas. Sand Consolidation The use of plastics or resins to bond unconsolidated sand grains. Scale Any inorganic solid material that precipitates in the wellbore of reservoir due to oil/gas production or related operations. Can severely reduce well productivity. Secondary Porosity Primary porosity is that found in the spaces between sand grains or carbonate clastics. Secondary porosity is developed later by leaching or diagenesis (pressure/temperature changes). Seismic Exploration method whereby vibrations are created at surface (dynamite, air-guns, vibrators/thumpers etc.) and the reflections off the subterranean rock surfaces are recorded on geophones. The results are processed by computers to provide the geophysicists with traces than can be interpreted to identify the rock structures (folds, faults, unconformities etc.). Shot Density Number of perforations per foot. Skin An indirect measure of the unexpected pressure drop near the wellbore. A dimensionless number. Revision 1: January 1995 211 WELL PRODUCTIVITY AWARENESS SCHOOL 212 Solubility A measure of the ability of a solid to dissolve in a liquid (temperature and pressure dependent). Stimulation A technique to improve well productivity. Stock Tank Barrel (stb) Expression to relate the volume of a barrel of oil at surface as opposed to a ‘reservoir barrel’. Oil ‘shrinks’ as it comes to surface. Each oil has a Bo measurement which relates the volume in the reservoir to the volume in the stock tank. TCP Tubing Conveyed Perforating Guns Unconformity A time break in the depositional sequence of rocks, e.g. much younger rocks deposited on an eroded surface of older rocks. This would indicate a break in the deposition of sediments in an area over a period of tens or hundreds of millions of years. Underbalanced Perforating Perforating conducted with a large pressure difference between reservoir (high pressure) and tubing (low pressure). Viscosity A measure of how easy a fluid will flow (honey is more viscous than water). Wax Organic product that deposits in reservoir, tubing, flowlines, pipelines. Big impact on well productivity. Work string Dedicated string of drillpipe or tubing. In stimulation, such a string would be used because of its acid resistance, pressure capability, and its cleanliness. Revision 1: January 1995