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Summary Back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem, necessitating costly and manpower-intensive surface-handling procedures. Further, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as this problem remains unsolved. The most cost-effective potential solution to this problem is provided by curable resin-coated proppant (RCP), which consolidates in the fracture. Early field trials with RCP's, however, were not completely effective in stopping the back production of proppant. Typically, some 10% of the total volume of RCP placed in the fracture was backproduced. Two types of RCP back production were identified: during well cleanup (Type A) and after a long period of proppant-free production (Type B). Type A is believed to be caused by an insufficient strength buildup of the RCP pack. The influence of factors affecting RCP pack strength buildup-resin type, reservoir (curing) temperature, resin/fracturing-fluid interaction (under shear and temperature), and erosion of the resin from the proppant grains, which can reduce the RCP pack strength-have been studied in the laboratory. Type B proppant back production was suspected to be caused by a previously unobserved phenomenon: damage resulting from stress cycling that the proppant pack undergoes each time the well is shut in and put back on production. Further, the applied stress increases as the drawdown is increased and the formation is depleted. We performed a laboratory study to help clarify the effect of curing temperature, water production rate, proppant size, and stress cycling on the integrity of RCP packs. The experiments confirmed the field experience that stress cycling has a dramatic effect on proppant back production of commercial RCP packs. The number of applied stress cycles (i.e., the number of times the well is shut in) and the initial RCP pack strength appear to be the dominant factors that govern proppant back production. Dedicated experiments are therefore required to evaluate the use of RCP's to eliminate proppant back production for a particular field application. Introduction Sand production is an operational problem that has plagued oil and gas wells producing from clastic formations since the early days of the oil industry. By contrast, proppant back production is found only in wells where hydraulically created fractures have been packed with (large) volumes of proppant. The proppant pack is unrestrained at the fracture mouth; once proppant grains enter the wellbore, they can be brought to surface with the well fluids. Such back production of proppant from hydraulically fractured wells, particularly those completed in the northern European Rotliegend formation, is a major operational problem. It necessitates costly and manpower-intensive surface-handling procedures (viz., the daily dumping of proppant) and on-site control of the chokes when beaning up the wells. Further, erosion of well and surface facilities presents a safety hazard, and proppant remaining in the wellbore can shut off production by covering the productive interval. Consequently, the development of unmanned platform operations offshore, required in today's economic climate, is impossible as long as significant proppant back production occurs. Incidentally, a similar tendency for hydraulically fractured wells to backproduce proppant is observed in Alaskan operations; however, owing to the different conditions (onshore oil production), the approach adopted there is "to live with it."
- Europe > Norway > Norwegian Sea (0.65)
- Europe > United Kingdom > North Sea > Southern North Sea (0.44)
- Europe > Poland > North Sea > Southern North Sea (0.44)
- Europe > Netherlands > North Sea > Southern North Sea (0.44)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Rotliegend Sandstone Formation (0.99)
- Europe > Poland > North Sea > Southern North Sea > Rotliegend Sandstone Formation (0.99)
- Europe > Netherlands > North Sea > Southern North Sea > Rotliegend Sandstone Formation (0.99)
Paper first presented at the 1993 SPE Annual Technical Conference and Exhibition held in Houston, Oct. 3-6. Combined with SPE 26563 and published in the Journal of Petroleum Technology, March 1994. Summary A relatively short, highly conductive fracture created in a reservoir of moderate to high permeability will breach near-wellbore damage, reduce the drawdown and near-wellbore flow velocity and stresses, and increase the effective wellbore radius. Fracturing treatments of this type have two stages:fracture created, terminated by tip screen out, and fracture inflation and packing. Such a two-stage treatment is the basis of a number of newwell-completion methods, collectively known as "frac-and-pack." This technique has been successfully applied, with a range of fracture sizes, to stimulate wells in various reservoirs worldwide. This paper discusses the criteria for selecting wells to be frac-and-packed. We show how a systematic study of the inflow performance can be used to assess the potential of frac-and-packed wells, to identify the controlling factors, and to optimize design parameters. We also show that fracture conductivity is often the key to successful treatment. This conductivity depends largely on proppant size; formation permeability damage around the created fracture has less effect. Appropriate allowance needs to be made for flow restrictions caused by the presence of the perforations, partial penetration, and non-Darcy effects. We describe the application of the overpressure-calibrated hydraulic fracture model in frac-and-pack treatment design, and discuss some operational considerations with reference to field examples. The full potential of this promising new completion method can be achieved only if the design is tailored to the individual well. This demands high-quality input data, which can be obtained only from a calibration test. This paper presents our strategy for frac-and-pack design, drawing on examples from field experience. We also point out several areas that the industry needs to address, such as the sizing of proppant in soft formations and the interaction between fracturing fluids and resin in resin-coated proppant. Introduction The idea of combining sand control and well stimulation in a single treatment was first practiced in Venezuela some 30 years ago. The treatment consisted of perforating the pay zone, then applying a small-scale fracturing treatment with a viscous crude (10 to 20 cp) and sand sizing to control formation sand. Ball sealers were used in long intervals to promote distribution across the entire section. A screen was washed down through the gravel remaining inside the casing after the fracture treatment, and additionals and was placed around the screen where necessary. This technique yielded relatively high production rates because of low skin and adequate sand control. This treatment was later extended to consist of a small, propped fracture designed to bypass the skin around wells completed in well-consolidated sands that were severely impaired. In this case, the screen was not run and the gravel was not topped up. A typical job for a 100-ft interval would consist of 500 to 800 bbl of crude oil (18 API) with some 40,000 lbm of 10- to 20-meshsand. This propped minifracture typically yielded a two- to three-fold increase in production rate. Though it received considerable publicity, to the best of our knowledge, the technique was never applied widely outside Venezuela. Nevertheless, the technology in this area has now developed to the point where the theoretical understanding of the processes involved has greatly improved, proven treatment design tools are available, and vastly improved mixing and pumping equipment has been developed for both gravel packing and propped hydraulic fracturing.
- South America > Venezuela (0.44)
- North America > Mexico (0.28)
- Europe > Netherlands (0.28)
- Well Completion > Sand Control > Frac and pack (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
This paper was combined with SPE 26563 and published in the Journal of Petroleum Technology, March 1994. Abstract A relatively short, highly conductive fracture created in a reservoir of moderate to high permeability will breach near-wellbore damage, reduce the drawdown, near-wellbore flow velocity and stresses and increase the effective wellbore radius. Fracturing treatments in such reservoirs consist of two stages:fracture creation, terminated by tip screen-out, and fracture inflation and packing. Such a two-stage treatment is the basis of a number of new well completion methods, known as "Frac & Pack". This technique has been successfully applied for a range of fracture sizes in various reservoirs in many parts of the globe. The selection criteria for wells to be Frac & Packed are discussed. It is shown how an inflow-performance simulator can be used for assessing the potential of Frac & Packed wells, to identify the controlling factors and to optimize design parameters. It is shown that fracture conductivity is often the key to successful treatment. This conductivity is largely dependent on proppant size; formation permeability damage around the created fracture has less effect. The application of the overpressure-calibrated hydraulic fracture model in the design of Frac & Pack treatments and some operational considerations are illustrated with reference to field examples. The full potential of this promising new completion method will only be achieved if the design is tailored to the individual well. This demands high-quality input data that can only be obtained from a calibration test. This paper presents the strategy we have worked out for Frac & Pack design, with illustrations from field experience. Several areas which need to be addressed by the industry, such as proppant sizing in soft formations and fluid-resin interaction during use of resin-coated proppant, are identified. Introduction The idea of combining sand control and stimulation in a single treatment was first put into practice in Venezuela some 30 years ago. The treatment consisted of perforating the pay zone, followed by a small-scale fracturing treatment using a viscous crude (10 – 20 cP) and sand sized so as to control formations and. Ball sealers were used in long intervals to promote distribution across the entire section.
- Well Completion > Sand Control > Frac and pack (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
Summary. Borate-crosslinked guar or hydroxypropyl guar (HPG) polymer solutions have become increasingly popular as hydraulic fracturing fluids. These fluids are cheap and environmentally friendly, and they minimally impair a propped fracture while yielding maximum viscosity. The drawbacks, which have limited their use, are a restricted temperature range of applicability, relatively high tubing friction, and poor stability when prepared with seawater. This paper shows how these drawbacks can be eliminated by a fundamental understanding of the relation between fluid chemistry (as a function of borate crosslinker, pH, and polymer/crosslinker concentration) and its physical properties (proppant-carrying capacity, viscoelasticity, and the temperature stability of the resulting crosslinked structure). Introduction Borate-crosslinked HPG and guar solutions have become increasingly popular as hydraulic fracturing fluids in well-stimulation operations. Guar fluids are clean, compatible with resin-coated proppant, and in many cases self-breaking. The one major hindrance to their widespread application has been a perceived limited temperature range. Viscous properties and proppant-carrying capacity depend on the number and strength of crosslink bonds, which are controlled by the chemical equilibrium of the borate-fluid systems. This, in turn, is influenced by temperature and pH. Optimum hydraulic fracturing treatments require the borate fluid to have stable physical properties (e.g., viscosity). During a hydraulic fracturing treatment, the fluid is transported down the tubing into the formation. The subsequent temperature rise will alter the chemical equilibrium, changing the pH, the number of crosslink bonds, and therefore the fluid viscosity. This is of great concern because, if fluid viscosity becomes too low, the proppant settling rate may increase sufficiently to cause undesirable proppant distribution over the fracture (e.g., only the fracture bottom may be propped and communication with the perforated interval is lost). The decrease in pH with temperature increases also is a function of the composition of the water used to prepare the base gel. The preferred operational technique for massive hydraulic fracturing (MHF) treatments offshore is to use a liquid gel concentrate mixed on the fly with filtered seawater. A major incompatibility arises with the use of seawater because it contains multivalent metal ions. These may precipitate as hydroxides, which reduces the fluid pH and drastically affects fluid properties. This paper discusses the relation between the chemical equilibrium of the borate/polymer complex and gel viscoelastic properties. We describe a methodology to optimize these properties and present experimental data on the viscoelastic properties of borate-crosslinked gels. Steady-shear rheological measurements were carried out to investigate the borate/polymer complexes, as well as oscillatory shear and static proppant-settling measurements. The Appendix gives the underlying chemistry of the borate/HPG crosslinking. The concept described in the Appendix is combined with the experimental data developed in the following sections to furnish a fundamental understanding of the system. Experimental Equipment and Instrumentation. The linear viscoelastic properties of borate-crosslinked gels were studied with a controlled-stress rheometer, Type CS50, built by Carri-Med Ltd., England. The measurements were performed with a cone-plate geometry; the cone had a 6-cm diameter and 1.5 angle. During these tests, the fluids were subjected to an oscillatory shear with a small amplitude, from which the complex shear modulus, can be derived. is composed of an elastic component, the storage modulus, and a viscous component, the loss modulus, . The oscillatory shear measurements were executed at 0.8 Hz, an optimum frequency that allows both moduli to be observed. These measurements were combined with static proppant-settling tests performed in 7.5 × 30-cm glass cylinders to investigate whether static proppant settling is a function of the strength and density of crosslink bonds. These measurements were performed at a proppant concentration of 10 vol% 20/40-mesh Ottawa sand. This proppant concentration was chosen because the maximum settling rate is observed at this value. At lower values, proppant clustering is prevalent; at higher concentrations, hindered settling becomes important. The values reported here use the formation rate of clear fluid at the proppant bank top. The proppant-settling measurements are split into three regimes: nearly perfect proppant suspension (settling velocity, <0.5 cm/min), marginally acceptable proppant suspension (0. 5 5 cm/min), and poor or unacceptable suspension capacity (>5 cm/min). We have not yet investigated dynamic proppant-settling, although we expect that the applied shear influences proppant settling rates in viscoelastic fluids. Steady-shear rheological measurements of crosslinked gels are difficult in conventional rotational viscometers. Borate fluids crosslink rapidly and form viscous gels, so the fluid will not remain in the viscometric gap (the Weissenberg effect). Further, owing to the dynamic nature of the crosslinking process (which demands some time for equilibration), a long-pipe viscometer is required to measure the flow curve. Neither of these conventional rheometers is ideal. We used the helical screw viscometer (HSV), a practical instrument that can "characterize" borate fluid rheological properties. The HSV contains a helical screw impeller rotating in a draft tube, as Fig.1 shows (it is based on Kemblowski's original). The impeller keeps the fluid in motion continuously and prevents it from climbing out of the measuring gap. The impeller shears the fluid at a known rotational speed while its torque is measured. The shear and temperature regime can be adjusted easily. The HSV is quick and easy to operate. A pH meter, Type pH-196, with an E-56 glass electrode containing 3 mol KCl + AgCl electrolyte supplied by WTW G. H., was used to monitor the pH changes as a function of temperature changes and chemical additions to the borate-fluid sample. The pH meter was calibrated at room temperature with two buffer solutions at pH's of 7.00 and 10.00, respectively. The pH measurements at elevated temperature are compensated for by measurements made with an accurate NTC temperature sensor in the fluid. The HSV also can measure the rheology of fracturing-fluid slurries containing up to 50 vol% proppant particles because it has a wide measuring gap compared with the proppant particle diameter, and it keeps the fluid in motion continuously to prevent particle settling. Fluid and Test Conditions. We used HPG for the above measurements. We did not test guar in this study, although we expect only minor deviations from the results reported here. SPEPF P. 165^
- Europe > United Kingdom > England (0.24)
- Europe > Netherlands > North Sea (0.16)
Summary Successful acid-fracturing treatment requires the creation of etched channels of sufficient width and length. This paper shows how the channel shape can be calculated using knowledge of the acid/rock reaction process, in-situ temperature and hydraulic profile. A simulator has been developed for this purpose, on the basis of an implicit finite-difference scheme permitting rigorous treatment of all relevant processes, such as the cooling of the rock adjacent to the fracture and the heat transfer between fracture and wall during and after pumping, is employed. Detailed knowledge of the temperatures of both the fracture fluid and the rock face allows quantitative description of the progress of the acid/rock reaction. Model calculations show that the channels etched in calcitic rock may be very wide near the wellbore because of turbulence effects. On the other hand, the etched channels may be too narrow in dolomitic rock, or rock with a low fracture toughness. This will impair well productivity, and should be avoided by modifying the pumping scheme. Two field examples of treatment design and evaluation using the new simulator are discussed. Introduction The objective of acid-fracturing well stimulation in carbonate rock is to facilitate the flow of reservoir fluids to the wellbore by creating long, conductive, acid etched channels. Acid, sometimes preceded by a viscous flush, is pumped downhole above fracturing pressure. The acid etches channels in the fracture walls, which are required to remain open after the treatment when the fracture has closed. The increase in productivity resulting from such treatment is strongly dependent on the width, length and conductivity of the channel formed. Viscous fingers may be formed depending on the mobility ratio of the fluid stages. Channel dimensions can only be predicted if the in-situ kinetics of the reaction between the rock and the acid is known. The reaction rate at any point on the fracture surface is critically dependent on the local temperature in the fracture during the treatment, which in turn depends on the in-situ energy exchange. The fluid velocity in a viscous finger is higher than that in the surrounding gel. This effects the local the energy balance and hence the local reaction rate. The in-situ heat transfer during acid fracturing is depicted in Fig. 1. Cold fluid is pumped into the fracture mouth, where it cools the fracture face and the interior of the rock adjacent to the fracture by both conduction and fluid leak-off. P. 477^
- North America > United States (0.68)
- North America > Canada > Alberta (0.28)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.89)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.86)
Abstract The theoretical understanding and technology of hydraulic fracturing has shown tremendous progress over the last ten years. This is illustrated by the significant commitment of oil and service company research funds over this period to develop the required capabilities. Fields period to develop the required capabilities. Fields which were previously uneconomic are now being profitably developed, employing modem profitably developed, employing modem hydraulic fracturing technology. The development of this technology required input from disciplines as diverse as rock mechanics, equipment engineering and production chemistry. Shell's participation in this high technology story is participation in this high technology story is illustrated by their research developments over the last ten years and the ways in which technological hurdles to applying the developments in the field have been successfully overcome. We show how the treatment size and aggressiveness has increased over the years so as to raise well productivity. The development of unique research equipment and its impact on material selection and treatment design is described. The understanding of the rock mechanical aspects of the fracturing process has been completely revised which, after field calibration, allows much more productive fractures to be placed. The application of this technology is placed. The application of this technology is illustrated by the development history of a 24-well offshore field. The high individual well production rates led to new problems with proppant back-production. The solution required a good understanding of the process, which was achieved via a fully integrated interdisciplinary project. project Introduction Hydraulic fracturing treatments are frequently required to ensure economic production rates from wells completed in low to production rates from wells completed in low to moderate Permeability formations. This type of stimulation treatment involves placing layers of proppant material in the created fracture thereby proppant material in the created fracture thereby greatly enhancing the inflow area of the formation to the wellbore. Hydraulic fracturing makes a significant contribution to the worldwide oil and gas production. It has proved to be capable of production. It has proved to be capable of increasing both well production and the ultimate recovery achievable from a particular well and/or field. The fracturing process was patented by the Amoco Production Company in 1949. Initially, technical progress was slow, given the need to develop both an understanding of the processes involved as well as reliable, specialized equipment. By 1981, it was already claimed that some 800,000 treatments had been performed with some 40% of all wells in North America being fractured. An additional eight billion barrels of oil had been added to reserves. Hydraulic fracturing has become increasingly important in international operations and will eventually be applied on a similar scale to that described above for North America in 1980. P. 637
- North America > United States (0.67)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Abstract A new polymer has been introduced into the oilfield for use in hydraulic fracturing. Its unique properties complement the wide range of polymers currently in use. This biopolymer was originally developed for enhanced oil recovery and is now also used for gravel packing and as a mud viscosifier. The biopolymer causes minimal formation/proppant-pack permeability impairment - yielding the highest permeability impairment - yielding the highest retained permeabilities of any polymer tested to date. It exhibits a constant viscosity up to a transition temperature (adjustable between 40 degrees C and 100 degrees C) beyond which the viscosity decreases to a level close to that of water. This eliminates the need for a breaker. The polymer is highly shear-thinning, resulting in the lowest tubing-head pressure of all fluids available. The good proppant-carrying capacity of the fluid is achieved without the addition of a crosslinker while fluid loss is similar to other polymers that are commonly used for fracturing. The formulation of a fully functional fracturing fluid for use at medium temperatures without the need for a breaker or crosslinker is unique. In particular, it can be used with resin-coated proppants where unwanted side reactions occur with conventional fracturing fluids. The new fracturing fluid was successfully tested in combination with resin-coated proppant in the Southern North Sea. Introduction A wide range of fracturing fluids is currently available for well stimulation fracturing treatments, e.g. crosslinked water-based gels, polymer emulsion fluids and foams. However, the performance of many of these fluids is far from ideal. So the quest continues for technically improved fluids that cause less damage to the proppant pack and the formation and offer a faster clean-up. The optimum fracturing fluid has to meet a large number of criteria: - Losses of fluid into the rock formation during a fracturing treatment must be small (i.e., the fluid'sefficiency, defined as the created fracturevolume divided by the pumped volume, must be high). - At high shear rates the viscosity of the fluid should preferably be as low as possible to avoid excessive friction losses in the tubing resulting in high tubing-head treatment pressures. P. 105
- Europe > North Sea (0.54)
- North America > United States (0.46)
- Europe > United Kingdom > North Sea (0.24)
- (3 more...)
Abstract The Western Canadian Foothills contain deep gas bearing dolomitic reservoirs in the Devonian Wabamum and Mississippian Turner Valley formations. The reservoir matrix permeabilities can be low (less than 0.1 mD) and the in-situ rock stresses high, with fracture gradients up to 24 kPa/m. In 1989, three wells, completed in these reservoirs, were fracture-stimulated with massive pad-acid treatments which significantly increased well productivity. Production increases up to five times the pre-frac flow rates were achieved. That success was the result of comprehensive laboratory and engineering studies to select and design the optimum treatments, strict on-site quality control, careful planning and execution of the jobs. Introduction The Western Canadian Foothills gas trend is located on the eastern slopes of the Rocky Mountains and extends from the Alberta/ Montana border in the south up and into northeastern British Columbia. The Rocky Mountains and Foothills were formed during a time of major east-west compression of the sedimentary deposits or the western Canadian basin which also resulted in a series of northeast-southwest-trending folded and thrust-faulted structures at depth. The Foothills play is characterized by relatively deep (3000 m to 6000 m), sour (H2S) natural gas reservoirs found in thrust faulted carbonate structures, predominantly dolomites of Mississippian and Devonian age in Alberta and of Triassic age in British Columbia. Shell has traditionally been and remains today an active player in the Foothills and has on production sour natural gas fields at Water-ion, Sorge, Jumping Pound, Burnt Timber, Limestone, Moose Mountain/Whiskey Creek, Panther River and Clearwater. In addition, recent Foothills discoveries have been made by Shell at Ram River in Alberta and Boulder in British Columbia. The productive formations in those fields are generally the Mississippian Turner Valley (Mt) and Pekisko (Mp), The Devonian Wabamun (Dwa), Nisku (Dn) and Reef (Dr) in Alberta, and the Triassic Baldonnel (TRb), Pardonet (TRp) and Charlie Lake (TRcl) in British Columbia. The porous rocks comprising Foothills productive formations are primarily dolomites and have low in-situ matrix permeabilities from less than 0.1 mD to 10 mD, with an average of around 2 mD. Natural fractures appear to play an important role in enhancing the productivity of these low permeability formations. The degree of enhancement varies from reservoir to reservoir and in some fields from well to well. An interesting aspect of the natural fractures is that they are often in filled with calcite which is dissolved at a much faster rate by hydrochloric (HCI) acid than the dolomite matrix. The result is enhanced permeability along the etched natural fractures. This is important during acid fracturing treatments as it results in high acid leakoff from the created fracture faces and the formation of acid wormholes. Massive Acid Fracturing (MAF) treatments using alternating stages of non-reactive pad fluid and acid have proven successful in reducing leakoff into natural fractures. Most wells in the Foothills respond well to conventional acid fracturing treatments. They generally comprise between 50 gal. to 250 gal. of HCI acid per foot of vertical pay.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.68)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.45)
- North America > United States > Alaska > Arctic Ocean > Arctic Basin > Amerasia Basin > Canadian Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Limestone Field > Wabamun Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabamun Formation (0.97)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Summary Equipment has been constructed to give a realistic laboratory simulation of the in-situ conditions during and after a hydraulic fracturing treatment of tight gas reservoirs (TlGRE). The equipment measures the permeability of both the "natural" core material and the proppant pack with gas under in-situ conditions before and alter exposure to fracturing fluid. The rate of cleanup of the proppant pack and the core sample is measured after the fracturing fluid has broken. Various fracturing fluids commercially available from the major service companies have been evaluated. Little damage to the proppant/rock interface has been measured, but massive damage to the proppant pack was observed. The damage is caused by fracturing-fluid residue, filter cake, and non-Darcy flow effects. This damage is observed only in the experiments described above and has not been reported in other less sophisticated laboratory simulations of the fracturing process. The least damaging of the commercially available products tested has been identified. Procedures have been developed for placing "overdesigned" (or increased-conductivity) proppant packs during field hydraulic fracturing treatments. This has resulted in large increases in well productivity during field treatment, which is particularly noticeable during the early (transient) production phase. It is concluded that there is scope for the development of less damaging fracturing fluids to optimize economics. Introduction In northwest Europe, an increasing number of gas fields are being developed, or are planned to be developed, in which hydraulic fracture stimulation is essential to obtain economic production rates. In many cases, the development of these fields will take place only if well production rates can be maximized by effective hydraulic fracture treatments. Therefore, a multidisciplinary research project was started in 1980 to improve the existing procedures and to develop new ones for improving tight-gas-reservoir well productivity. This paper deals with one of the aspects evaluated as part of the production technology study. A new fracture conductivity cell, the TIGRE tester, was constructed for this project. This tester enables measurement of all interactive processes between the formation, proppant, fracturing fluid, and high-pressure gas under simulated downhole conditions. The TIGRE-tester equipment and experimental procedures are described. Experiments with the equipment showed a larger reduction in the proppant pack than reported previously, while little formation damage was measured. Non-Darcy flow effects in the fracture were found to be of major importance. To compensate for the significant reduction in proppant-pack permeability, it was recommended that the proppant concentration be increased during hydraulic fracture stimulations with the cleanest commercially available fracturing fluid. The results of a stimulation campaign, during which a number of the recommended improvements were introduced, are presented. TIGRE Tester Equipment Design. During a fracturing treatment in low-permeability sandstone, fracturing-fluid filtrate will penetrate into the formation through the fracture face. This may cause impairment as a result of water blocking, clay swelling, and penetration of fines entrained in the fluid. Furthermore, strength reduction of the formation rock matrix adjacent to the fracture face may initiate collapse and/or plugging of the fracture wall, proppant embedment in the fracture face, and plugging of the proppant pack. The TIGRE tester has been constructed to simulate all these effects simultaneously. In this experimental apparatus, the face of a piece of artificial fracture wall can be exposed to fracturing fluid under simulated downhole conditions. Ultimately this involves downhole temperatures, pressures, and stresses; initial water and gas saturations in the core material; and downhole flow regime (such as shear rate). To describe the fracture impairment, both the fracture-wall and proppant-pack permeabilities should be measured. Proppant-pack impairment could be caused by proppant embedment into the fracture wall and the plugging with formation debris and fracturing-fluid residue. The relative importance of embedment and plugging varies with different test conditions and other reservoir and proppant materials. Therefore, both phenomena have to be measured separately by recording both the fracture conductivity and the fracture closure (by monitoring the fracture-wall displacement). In addition to debris from the fracture wall, fines from crushed proppant grains and precipitates from the fracturing fluid may also cause plugging of the proppant pack. Care should therefore be taken in controlling both proppant and fracture-fluid properties. The TIGRE-tester design criteria are illustrated in Fig. 1. The tester simulates the production processes in and around the fracture at depths of up to 10,000 ft [3000 m] and enables measurement of permeabilities as low as 1 µd. A small cylindrical element of the fracture wall with the adjacent part of the fracture is modeled in Fig. 2. It is assumed that there is a plane of symmetry in the center of the fracture. Therefore, the thickness of the proppant layer has to be half the actual fracture width, with an 0.18-in. [4.6-mm] proppant pack being typical. Fig. 3 is a block diagram of the TIGRE tester. The heart of the apparatus is a 14,000-psi [96.5-MPa] pressure vessel for cylindrical test samples with a 2-in. [5-cm] diameter. Lateral stress on the sample is applied by the fluid pressure exerted on the rubber-sleeved sample. The piston above the sample provides the axial, fracture-closing stress, while allowing hydrocarbons to flow through the core sample. A more detailed description of the equipment and of its operation is given in the Appendix. The tester is capable of measuring permeability as a function of gas flow rate in both the formation and the proppant pack before and after exposure to fracturing fluid. The gas may be either dry for measuring single-phase permeabilities or saturated with water for measuring relative (two-phase) gas permeabilities. Equipment Design. During a fracturing treatment in low-permeability sandstone, fracturing-fluid filtrate will penetrate into the formation through the fracture face. This may cause impairment as a result of water blocking, clay swelling, and penetration of fines entrained in the fluid. Furthermore, strength reduction of the formation rock matrix adjacent to the fracture face may initiate collapse and/or plugging of the fracture wall, proppant embedment in the fracture face, and plugging of the proppant pack. The TIGRE tester has been constructed to simulate all these effects simultaneously. In this experimental apparatus, the face of a piece of artificial fracture wall can be exposed to fracturing fluid under simulated downhole conditions. Ultimately this involves downhole temperatures, pressures, and stresses; initial water and gas saturations in the core material; and downhole flow regime (such as shear rate). To describe the fracture impairment, both the fracture-wall and proppant-pack permeabilities should be measured. Proppant-pack impairment could be caused by proppant embedment into the fracture wall and the plugging with formation debris and fracturing-fluid residue. The relative importance of embedment and plugging varies with different test conditions and other reservoir and proppant materials. Therefore, both phenomena have to be measured separately by recording both the fracture conductivity and the fracture closure (by monitoring the fracture-wall displacement). In addition to debris from the fracture wall, fines from crushed proppant grains and precipitates from the fracturing fluid may also cause plugging of the proppant pack. Care should therefore be taken in controlling both proppant and fracture-fluid properties. The TIGRE-tester design criteria are illustrated in Fig. 1. The tester simulates the production processes in and around the fracture at depths of up to 10,000 ft [3000 m] and enables measurement of permeabilities as low as 1 µd. A small cylindrical element of the fracture wall with the adjacent part of the fracture is modeled in Fig. 2. It is assumed that there is a plane of symmetry in the center of the fracture. Therefore, the thickness of the proppant layer has to be half the actual fracture width, with an 0.18-in. [4.6-mm] proppant pack being typical. Fig. 3 is a block diagram of the TIGRE tester. The heart of the apparatus is a 14,000-psi [96.5-MPa] pressure vessel for cylindrical test samples with a 2-in. [5-cm] diameter. Lateral stress on the sample is applied by the fluid pressure exerted on the rubber-sleeved sample. The piston above the sample provides the axial, fracture-closing stress, while allowing hydrocarbons to flow through the core sample. A more detailed description of the equipment and of its operation is given in the Appendix. The tester is capable of measuring permeability as a function of gas flow rate in both the formation and the proppant pack before and after exposure to fracturing fluid. The gas may be either dry for measuring single-phase permeabilities or saturated with water for measuring relative (two-phase) gas permeabilities.
- Geology > Mineral > Silicate > Phyllosilicate (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.44)
SPE Members Abstract Polymer emulsion hydraulic fracturing fluids were widely employed some 10 to 15 years ago, but became less popular after the introduction of crosslinked, water-based gel systems. The latter were thought to have a higher viscosity and be easier to handle, as well as being cheaper. However, during the last few years, polymer emulsions have enjoyed an increasing popularity in Europe because of their flexible viscosity response and their non-damaging properties. In addition, their cost per unit volume of proppant placed is now comparable to that of water-based fluids. Addition of a well-dispersed internal phase will increase the viscosity of any fluid over that of the external phase alone. For polymer emulsion fracturing fluids the continuous phase is gelled water, the viscosity being enhanced by the addition of diesel, kerosene or crude oil at typical volume fractions between 0.5 and 0.7. During the proppant stage, the fluid rheology is further complicated by the addition of a second internal phase (sand) to the emulsion, which will not only increase the viscosity, but will also affect the stability of the emulsion if the total internal phase (sand + oil) exceeds a maximum value. However, the existence of two different internal phases offers the possibility of gearing the volume fractions of two alternate phases to each other in such a way that the slurry viscosity is constant and independent of the sand concentration. This is particularly important in situations where the tubing head pressure is limited and tubing friction becomes critical and cannot be allowed to increase as the sand concentration is increased during the job. A last, but not the least, parameter affecting the emulsion rheology is the amount of shear applied to the emulsion while generating it. It was noticed that emulsions prepared in the field had a lower viscosity than emulsions prepared in the laboratory. This difference could be attributed to a different oil droplet size distribution in field- and laboratory-prepared samples. The efficiency of the equipment used in the field to generate an emulsion lags behind that of laboratory equipment, especially at high oil/water ratios and high gel loadings. This is an area where further improvements can be made by the service companies. Polymer emulsion frac. fluids are thus attractive because of the wide span of control available to the operator. Field data (THP and BHP data) proved that these rheological correlations effectively described the situation in the field, the predictive accuracy of the formulae being such that the fracture shape may be evaluated from THP data. Some 25 fracturing treatments have been carried out in Europe using polymer emulsion fracturing fluid with a very high success ratio. Productivity improvement factors of nearly 30 were achieved with few operational problems using sand concentrations up to 14 lb/U.S. gal. Introduction Polymer emulsion hydraulic fracturing fluids were widely employed some 10 to 15 years ago, but became less popular after the introduction of crosslinked, water-based gel systems. P. 235^