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Collaborating Authors
Well Completion
Abstract Inefficient well operations result from a variety of poor production operations. An improperly designed rod string, improper size pump, incorrect stroke length, over-sized pumping unit, improperly sized motor, excessive casing pressure and many other parameters of a beam pumping system can result in inefficient operations. One of the most common causes of low efficiency is an efficient downhole gas separator. The low efficiency can result in excessive electrical power usage, a decrease in the amount of production from the well and additional maintenance requirements due to inefficient loadings of the pumping unit, rod string, motor and pump. Inefficient gas separators can be identified by obtaining an acoustic liquid level test which indicates a high gaseous liquid column above the pump and the analysis of dynamometer data which indicates incomplete pump fillage. Periodic acoustic liquid level tests and dynamometer measurements should be performed to verify that the downhole gas separator is operating efficiently. Tapping bottom with the pump, running the pumping unit at excessive speed, operating the pumping unit for excessive periods of time, increasing the tubing pressure or increasing the casing pressure is not the proper procedure for correcting inefficient downhole gas separation. Progressive cavity pumps operate much more efficiently with proper lubrication. A good gas separation that removes free gas from the liquid that enters the PC pump results in longer pump life, additional production and more efficient electricity usage and operation. The first attempt to correct inefficient downhole gas separation should be to set the pump below the fluid entry zone if feasible. This is the most efficient method of downhole gas separation. However, if the pump is set above the fluid entry zone, a gas separator should be used that offers an efficient gas/liquid separation chamber with low dip tube friction loss which results in complete pump fillage if sufficient liquid inflow into the wellbore is available. Downhole gas separators are divided into two types that are very different. If the gas separator is placed below the fluid entry zone, a single dip tube type of gas separator should be used below the pump seating nipple. If the gas separator is placed in or above the fluid entry zone, a gas separator assembly should be used that consists of an outer barrel having ports at the top of the barrel with a dip tube extending from the pump inlet down into the outer barrel and opening below the ports. An operator should be able to tell whether a gas separator is being used above or below the formation after viewing the gas separator. They should be built differently. In this paper, the outer barrel of the gas separator to be used above the formation is called outer barrel. It is sometimes called a mud anchor. The inner tube is called a dip tube and it is sometimes called a gas anchor. Clegg discusses many types of gas separators and the principles of gas/liquid separation.
- North America > United States (0.47)
- Europe > Norway > Norwegian Sea (0.24)
- Well Completion (1.00)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Abstract Most fracture stimulations are carried out using either water or oil-based fluids. Water-based systems have proven to be non damaging except in undersaturated formations. Project economics show that water-based fluids are less expensive and safer. Water-based fracture treatments at Crestar are normally conducted as the first phase of well stimulation. In undersaturated reservoirs, though, post fracture load fluids can be lost due to reservoir plugging, making the well uneconomic. Fortunately, the well is not permanently damaged and can be re-fractured with an oilbased fluid. Two wells, one producing oil from the Glauconite formation (14–20-39-4W5) and the other a gas producer completed in the Viking formation (4-8-39-8W5) were fractured with a cross-linked water-based fluid. Both wells failed to respond to the stimulation, had very low load fluid returns, and were considered for abandonment. An extensive review of the reservoir and offset wells, plus a rigorous reinterpretation of the 14–20 & 8–4 well logs, suggested the poor post fracture performance could be linked to low bulk volume water (BVW). Oil-based re-fracture programs were designed and placed in both wells resulting in economic production. Log analysis concluded that formations with BVW%s of 3–3.5' or less to sandstone are better suited to an initial oil fracture stimulation. Because the crossed-linked water stimulations sanded-off early with only a few tonne of proppant placed in the reservoir, two tonne of 100 mesh sand was added to the pads of the oil stimulations to help increase placement to 20 and 28 tonne, respectively. The increased propped fracture length and flowback of the oil load fluid combined to make the stimulations successful. Company wide, the cost savings from water-based stimulations have provided a higher netback, increasing the number of new well candidates for fracture technology, thus increasing overall production and reserves. Work is currently underway to provide a more reliable log-analysisbased screening method for identifying which wells will definitely not accept a cost saving water fracture treatment, thus saving some re-fracture costs. Introduction Oil & gas companies in North America compete for the sale of produced oil with the rest of the world. Cost per barrel to produce is always the key issue. Companies try continually to reduce the costs of drilling, completion, and tie-ins, while using newer technology to increase production rates and reserves. Wells drilled today tend to be deeper as conventional oil and gas becomes harder to find, adding to drilling and completion costs. This paper will show only the cost reductions for completions, specifically how fracture stimulation costs have been reduced. In general, refracturing of wells to enhance production has met with moderate success, mainly because many reservoir pressures have already been drawn down to free-gas conditions and a new frac produces under three-phase flow instead of two phases, essentially cutting oil production by a factor of 4 times due to relative permeability effects. Gas rates even as low as 5 e3m3/d affect oil production of less than 5 m3/d. Load fluid clean-up can also be a problem due to low energy flowbacks.
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing > Re-fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Husky Oil Operations Limited (Husky) has substantial undeveloped heavy oil resources in the Aberfeldy General Petroleum (GP) formation in the Lloydminster area. The oil has a gravity of 14 to 15 °API and a dead oil viscosity of approximately 3000 mPa.s. Husky pursued horizontal well technology in an attempt to realize the GP resource. The first horizontal well (1996) had good initial productivity but was uneconomic as the well had problems with gas impeding the pumping operation, limited inflow, and sand blocking in the liner. Learning from this experience, a second horizontal well was designed, drilled, and put on production in September 1998 with a continuous loading and sand cleanout string that was landed in the toe of the well. Early results are very encouraging as the wellhas higher production rates with good toe-to-heel communication. This paper reviews the GP reservoir properties and the first horizontal well production experiences. For the second horizontal well, the initial production results and design of the load/cleanout string are presented. In addition, research and development of sand transport in horizontal wells and remaining issues that require further development are discussed. Introduction The Aberfeldy field is located on the Saskatchewan side of the Lloydminster heavy oil block in an area roughly 6 sections wide. It straddles the 27W3 range line across townships 49 and 50 as shown in Figures 1 and 2. The Sparky formation, which is located immediately above the GP, has been extensively exploited in this area using such schemes as waterflood, steamflood, and fireflood. The existing Sparky producers are on late life primary production with the number of wells declining. In the last seven years 17 vertical wells have been completed into the GP sand along with 6 new well completions and 6 recompletions below the Sparky steamflood. To-date, with the exception of the steamflood recompletions, the GP producers have averaged only 2.0 m/day oil (OPD) and 3.2 m/day water (WPD). Also the 0.5% to 1.5% recovery factor is far below the 7% to 10% that would normally be acceptable. Therefore development of this zone, with vertical wells has proven to be uneconomic due to low production rates and low recovery factors. Because it also didn't produce any significant quantities of sand, it is believed that a horizontal well would have potential in this environment. As noted, the formation of interest is the GP sand formation, which is in the Lower Cretaceous Mannville Group. Extensive 40-acre spacing well control provides a good basis for analysis of the GP formation. There is a general lack of density logs in the Aberfeldy field, however, several wells cored in the GP, under the steamflood in section 20-49-26W3M, provide porosity and permeability data. The depositional environment of the GP in the Aberfeldy area is interpreted as shallow marine. It consists of a single overall coarsening upward sequence of well sorted, very fine grained quartzose sandstones capped by a thin siltstone unit that is overlain by marine shales of the Basal Sparky Unit.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Enhanced Sand Control Operations With a Newly Designed And Manufactured Meshrite Filter
Toma, P. (Alberta Research Council) | Korpany, G. (Alberta Research Council) | Scott, K. (Alberta Research Council) | Johanson, L. (Alberta Research Council) | Russel, T. (Secure Oil Tools) | Begg, S. (Secure Oil Tools)
Abstract Controlling sand inflow during the production of oil and bitumen from unconsolidated formations presents an important challenge for the industry. From 1985 to 1996 a novel Meshrite (compressed metallic wool) filter has undergone a period of laboratory and field testing. Laboratory and field results have shown that the performance of this device compares favorably with that of slotted liners and screens. In testing under similar sand/fluid inflow conditions, the amount of sand produced using the new filter was reduced considerably from that using slotted liners and screens, while the pressure drop measured across the filter and skin region increased only slightly, within acceptable limits. As a consequence, oil production increased while maintenance costs were reduced. However, prior to 1996 the complication and cost of manufacturing the new filter made it less than competitive on the market. A novel manufacturing technology that substantially increases the competitiveness of the new filter was developed during 1996–1997 by Secure Oil Tools. Subsequently a methodology for testing and improving the design of the filter was developed by the Alberta Research Council (ARC). This methodology and the resulting improvements in the design of the filter, are the focus of the current paper. To measure near-well sand transport and retention mechanisms with different filter designs and formation sand, a new experimental rig was used. A filter quality test was developed to check the manufactured quality of the filter, and to observe potential degradation of the filter as a result of exposure to a corrosive environment. Using the laboratory data acquired a new partial retention model is proposed here to better explain the mechanism of partial retention with the Meshrite filter and to offer a basis for comparing Meshrite with conventional slotted liners and screens. Introduction Since 1990, a compressed metallic wool filter has been tested extensively in the laboratory and the field as a solid control device for unconsolidated formations. The application of this solids control device to a wider variety of field conditions has been limited due to:manufacturing technology problems (an imported pre-packed compressed metallic wool was locally assembled with a perforated support casing); less than competitive price; limited density of imported pre-packed compressed wool; the outside diameter of the filter-well was too large for replacing conventional applications using screens; and lack of laboratory data using the real, cylindrical filter geometry. To assess and compare the retention efficiency of different sand control completions, the ARC has developed novel laboratory testing methods, including:a computer-assisted method for rapid evaluation of sand distribution that compares satisfactorily with conventional (wet & dry) sieving, requires a relatively small sample and is performed at a considerably lower cost; a computer-assisted method for matching the particle size distribution of a formation sand with a blend of sorted sand to ensure a consistent sand pack during filter testing and comparison; and three types of flow testing apparatus
- North America > United States (0.68)
- North America > Canada > Alberta (0.48)
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
Abstract The continuing use of combined cross linked polymer, propellant and acid fracturing treatment technologies has resulted in additional reserve development in a mature waterflood field in Wyoming. These three technologies have been used in combination on over 40 wells during 1996 and I997 in the Oregon Basin Field located in Park County, Wyoming U. S. A. The first use of Arcylamide-polymer/Cr III-carboxylate (Gel) Technology in Oregon Basin took place in the mid-1980's. The treatments are used to reduce water production in producing wells and improve both vertical and areal conformance in injection wells. Acid stimulations have been used since the 1940's as a means of improving production, with the first acid fracturing treatments being pumped in the late 1980's. Beginning in I996, these two technologies were combined in an attempt to successfully increase oil production from wells that had not been considered acid stimulation candidates due to their total productivity. Propellant was used as a perforation breakdown technique after pumping the Gel treatment and prior to the acid stimulation. This paper will briefly discuss the evolution of the Gel and acid fracturing treatment designs, and the reasons for combining the two treatment techniques. The results of the 1996–97 program will be discussed in detail, as well as the changes in the treatment designs that have taken place during the project. Data will be presented that confirms accomplishment of the treatment objective. Introduction One of the primary producing zones in Oregon Basin, the Embar formation, is a carbonate in which the lower portion of the interval is more highly fractured and of higher porosity than the upper portion of the interval. Processed open hole logs from recent infill wells (Fig. 1) indicated that the lower portion of the interval had been depleted to a much lower oil saturation than the upper interval. This differential depletion is believed to be attributable to significant vertical permeability variations and inefficiencies in the waterflood. Rock property variations and natural fracturing within the interval have made it difficult to effectively stimulate the upper portion of the pay interval. This has also contributed to the ineffective depletion of the zone. Gel treatments have historically been successful in reducing adverse channeling from injection to production wells and in reducing water production in producing wells. The treatments have generated significant incremental reserve development over the life of the field. Acid stimulations have also made a significant contribution to reserve development in Oregon Basin. These treatments have evolved from small volume "matrix" type treatments in the 1940's to larger volume acid fracturing treatments in the late 1980's. Foam fracturing has been used in the past few years, utilizing gravity segregation concepts to more effectively stimulate the upper, less depleted portion of the pay interval. This paper describes the continuing use of the combined Gel, propellant stimulation and acid fracturing technologies that have been used in Oregon Basin since 1996. The combination of these technologies has resulted in significant reserve development and has been applied to both production and injection wells.
- North America > United States > Oregon (1.00)
- North America > United States > Wyoming > Park County (0.54)
- North America > United States > Wyoming > Bighorn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Wyoming > Big Horn Basin > Oregon Basin Field > Tensleep Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Embar Field > Permian Formation (0.98)
- (2 more...)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.88)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.87)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (0.55)
Abstract Optimum fracturing is very important and what reservoir managers expect in order to exploitate reservoirs effectively. It is difficult to both reservoir managers and service operators to assess a treatment whether an optimum one because a underground fracture is invisible and immeasurable. Previously some individual techniques such as shut-in pressure analysis and well test after a treatment were presented in the evaluation of hydraulic fractures. However, using all the techniques in one evaluation and comparing the different results are not reported to our scope. Several evaluating techniques have been integrated and a software platform has been developed to evaluate a hydraulic fracture using recorded information during injecting and the tested data after a treatment. These techniques include treatment simulation, pressure decline analysis, transient well test and the evaluation of production performance. A case is investigated by these techniques and the comparison and comments are presented in this paper. Ability to understanding a hydraulic fracture has been improved a lot and the confidence can be enhanced in further optimum designing and treating having these integrated techniques. Introduction Economic optimum of hydraulic fracturing is what people expect in petroleum industry. To achieve this goal much work was done in past more than ten years. Veatch firstly outlined the concept of optimization of hydraulic fracturing treatments on the basis of NPV(net present value). Following Veatch's study Warembourg gave out the detail and general steps for optimizing hydraulic fracturing treatments. Then many applications in determining and practicing optimum fracturing have been attempted and now many methods and rules to determine optimum fractures are widely used in the industry. However, although a optimum treatment or fracture can be planned very well and designed very accurately before operating it is still questionable and difficult to answer that whether a proppanted fracture is optimum and a fractured operation is the best one because a underground fracture is invisible and immeasurable directly. In addition, a practical fracture usually differs from a designed one as in-situ parameters are not completely the same as those used in the design. Therefore, the evaluation of a existing fracture or a treatment is very important to both reservoir engineers and service operators. Recent years much effort has been made in order to assess existing fractures and fracturing treatments and now many evaluation methods are available. The methods include well test, pressure decline analysis, treatment simulation and performance evaluation etc.. In order to evaluate fracturing treatments and fractured fractures comprehensively, a integrated software platform called AFDDE (Acidizing & Fracturing Design, Diagnosis and Evaluation) is developed based on the above analyses, which is financially supported by service companies. This paper presents the main analysis techniques in the platform and a case application. FRACTURE EVALUATION TECHNIQUES The information feeding back from treatments and fractured fractures is treatment records (including treating pressures, rates, and pressure decline after shutting in etc.), production performance after treatments and pressure build-up or pressure down test data after treating. In according to the different information, a suitable interpreting techniques may be selected.
- South America > Colombia > T Formation (0.99)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The tight gas resource potential in the Western Canadian Sedimentary Basin is enormous. To date, however, it remains relatively unexploited and underdeveloped. The use of multiply fractured horizontal wells (MFHW) appears to be the "breakthrough" technology needed to economically exploit reasonably thick tight gas zones with effective in-situ permeabilities between 0.1 mD and 0.005 mD. This exploitation technology is already being applied in Europe and, in a more limited extent, in the U.S. Its application in Canada is currently being tested and/or evaluated by several of the larger majors. (This technology also has the potential for enhancing the deliverability of conventional gas.) An analytical model has been developed to predict the deliverability and production forecast of a multi-fractured horizontal well in a tight gas pool that includes the initial, transient production period. Using the DTC (discounted technical cost) approach to evaluate the economic feasibility of tight gas resources, the majority of the deep, high pressure tight gas evaluated in this study appears to be commercially viable, even at today's gas prices. Advances In Tight Gas Production Technology Historically, the development of tight gas reservoirs has involved drilling vertical wells and hydraulically fracturing them, often with the use of large amounts of proppant. These large fracs are known as massive hydraulic fracs (MHF) and typically involved hundreds of thousands or even millions of pounds of proppant. Quasi government bodies in the United States, such as the Gas Research Institute (GRI) and the Department of Energy (DOE), have been heavily involved in promoting research into the production of tight gas sands (Ref. 1). The GRI and Advanced Resources International (Ref. 2) have highlighted four key new technologies which they believe have the greatest application for the efficient development of tight gas sands:3D Seismic Integrated Approaches to Natural Fracture Detection Improved Well Completions/Stimulations Selected Use of Horizontal Wells We believe that multiply fractured horizontal wells (MFHW) is one such technology. Spencer (Ref. 5) surmised that natural fractures played a key role in the production of most tight gas reservoirs so that if the extent and direction of the natural fractures can be predicted and is sufficiently intense and laterally extensive, horizontal and/or multi-lateral wells can be used to promote otherwise uneconomic pay zones. The logical corollary to this is to question whether a network of induced fractures from a horizontal well could be used where the natural fissuring has limited development; and, particularly, where the stress regimes allow the resulting induced fractures to intersect the natural fissuring. Multiple Fractured Horizontal Wells (MFHW's) Mobil patented this stimulation concept in 1973 and applied it in deviated wells (Ref. 3). The technique was first applied in a horizontal well in 1987 by ARCO in the Spraberry formation. In October 1988, Mobil also successfully performed five fracs off a horizontal oil well in the Spraberry formation at 2420 m in John Snowden #7 near Midland, Texas (Ref. 5). However, these first two attempts were reportedly technical successes but economic failures.
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Midland County > Midland (0.24)
- Overview (0.34)
- Research Report > New Finding (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Wyoming > Tip Top Field > Utah-Wyoming-Idaho Overthrust Belt Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (9 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
Abstract Cold production is a recovery process used in unconsolidated heavy oil reservoirs in Alberta and Saskatchewan, Canada. In this process, sand and oil are produced together under primary conditions. Oil production rates can typically increase by one order of magnitude when sand is produced. The production of sand into a perforation was modeled using a horizontal sand pack flooded with live oil. Previous sand production experiments were performed using dead oil. The pack was scanned with an X-ray computed tomography (CT) scanner. A wormhole (high porosity channel) developed within the sand pack starting at the production end as soon as the back pressure was decreased suddenly from 780 psi (5.38 MPa) to 500 psi (3.40 MPa). The wormhole was stable to collapse when the production pressure was decreased from 780 psi (5.38 MPa) to 500 psi (3.4 MPa) and maintained at that pressure for 3 hours. The wormhole developed within the high porosity region (lowest cohesive strength) of the sand pack indicating that worn-holes in the field will likely develop in the weakest sands which are normally the sands with little cementation and therefore more oil. Under this rapid depressurization, gas did not come out of solution while the back pressure was maintained at 500 psi (3.4 MPa). The wormhole collapsed when the production pressure was decreased to atmospheric pressure. This indicates that a sudden decrease in the bottom hole pressure in a well may lead to wormhole collapse. Introduction Cold production has been used with commercial success to recover heavy oil in the Lloydminster area of Alberta, Canada. High production rates have been reported for heavy oil fields under primary recovery when large quantities of sand are produced with the oil. Several authors have attributed this high oil production rates to the formation of high permeability cavities, channels (wormholes) or both. Solution gas drive is generally considered to be the main drive mechanism. In many cases, solution gas drive by itself is not sufficient to explain the enhanced oil recovery. Significant increases in oil production occurred only when large quantities of sand were produced. Experiments in sand packs with live oil (without sand production) have shown that the permeability of the sand pack is not increased when gas bubbles are generated. Tracer experiments between injection and production wells have been performed in the field by several operators to measure the travel time between wells after considerable sand production has taken place. In general, this time was at least one order of magnitude shorter than that normally predicted for unaltered formations. These anomalously short times were explained by the formation of either fractures or wormholes. Theoretical models of cold production, which assume that a radial zones of dilated sand develops from a wellbore when sand is produced into a well, have been developed. The assumption of a large dilated zone around a wellbore differs from our observation of a high permeability channel (wormhole). Materials The Clearwater sand used in the experiment was obtained from the collection tanks at Suncor's former Burnt Lake pilot project.
- North America > United States (1.00)
- North America > Canada > Alberta (0.55)
Abstract Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs in order to reduce apparent skin and thus improve well productivity. The remaining post fracture rate dependent skin effect varies from case to case and it is unclear whether this is a result of non-Darcy flow in the fracture, the reservoir or both. This paper presents a study of the effects of reservoir and fracture turbulence in fractured gas wells. First, a quantification of the fracture length required to eliminate the effects of reservoir turbulence is obtained by means of a numerical study. A similar study with non-Darcy flow in both the reservoir and the fracture results in a correlation of fracture length required to get zero apparent skin at 75% of AOF as a function of reservoir permeability, pressure, fracture conductivity and β factor. Introduction As shown first by Forschheimer (1901) flow through porous media deviates from the linear Darcy's law and can be described by a quadratic equation with a non-Darcy flow coefficient β in the non-linear term. The coefficient β has been correlated to reservoir permeability by numerous authors; in general β decreases with increasing reservoir permeability. Experience has shown that the non-Darcy term becomes more significant in higher permeability gas reservoirs. Generally for reservoir permeabilities below 1 mD there is little effect from non-Darcy flow. In higher permeability reservoirs non-Darcy flow can significantly restrict well production rates and may also affect the pressure transient response. Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs. Normally the goal for hydraulic fracturing high permeability gas wells is to bypass skin damage and thus increase initial flow rates. These ‘skin’ fractures are generally small in nature and may or may not include high-grade proppants. Prior to performing such a treatment there is often evidence to support a high permeability reservoir and a high apparent skin. Unfortunately there is rarely enough data to distinguish if this skin is a true mechanical skin or rate dependent (non- Darcy) skin. Post fracture analysis may show apparent skins ranging from slightly stimulated to neutral to positive. If a multi-rate post fracture test was performed it is sometimes possible to separate mechanical skin from rate dependent skin. The basic problem with applying the rate dependent skin analysis to a fractured well is that the rate dependent skin was developed based on the assumption of radial homogeneous flow into the wellbore. By adding a hydraulic fracture the flow regime has been altered and the theory breaks down. It is unclear whether the rate dependent skin is occurring in the linear fracture flow or in the reservoir or in both. The primary purpose of this study was to quantify when reservoir turbulence is insignificant for a fractured well. The second purpose was to provide a simple method for predicting post fracture rates in high permeability reservoirs taking into account fracture turbulence.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract Polymeric damage is due to inconsistent or incomplete breaks of stimulation fluids as well as dynamically formed filter-cakes produced by drill-in fluids or drilling muds. Several methods have been employed with limited success to remove polymeric damage in an effort to increase well productivity. Prior treatments to remove this type of damage consist either of bleach (sodium hypchlorite) or acids. In case of horizontal wells with slotted liners or screens bleach or acids are not preferred. Additional expensive trips have become mandatory when coiled tubing or drill-pipe are utilized for spotting the treatment. Additionally, the mineralogy of some formations precludes the use of acids. Recent extensive research was conducted to develop a treatment which could effectively reduce this type of polymeric damage in either horizontal or fracture stimulated wells. Core flow evaluations and regained conductivity testing have shown that multi-fold improvements can be achieved even at elevated temperatures exceeding 250 °F and over a wide pH range. A case study of several low productivity wells suffering from polymeric damage was conducted. Post-frac production histories and return flow analysts were evaluated to characterize the damage and guide the remedial treatment design. A detailed study of field case histories including 11 fracture stimulated wells, which were suffering from polymeric damage, are presented and demonstrate how multi-fold improvements in well productivity could be achieved. Introduction And Statement Of The Problem Polymeric damage to proppant pack and formation permeability can significantly decrease well production. Insufficient gel degradation of drilling, completion, or stimulation fluids and dynamically formed filter cakes are responsible for impaired hydrocarbon recovery. Polymers are frequently employed within this industry for drilling, completion and stimulation operations. The polymers used are selected based upon their ability to provide viscositication, proppant transport and/or suspension, fluid loss control and zonal isolation. Yet the very properties for which they are chosen also make them difficult to break down following their application. Unbroken filter cake and insoluble high molecular weight polymer fragments are just two forms of damage produced by polymers. It is these residual effects of polymers that are responsible for reducing productivity through damage to a formation's permeability and conductivity. Hydraulic fracturing is one application through which significant polymer damage can occur. Treatments usually require gel systems utilizing high polymer loadings, yielding tremendous viscosity, in order to propagate the fracture and transport proppant therein. Due to the effects of fracturing treatments, such as fluid leak-off and fracture volume reduction upon closure, the polymer becomes concentrated on the formation face and within the proppant pack. At times the concentration of this polymeric filter cake becomes so high that breaker additives are no longer able to thoroughly degrade it. The goal then becomes the reduction or removal of the polymer damage in order to obtain optimum productivity in the most cost-effective manner. Filter cakes are dense and are a practically insoluble concentration of polymer deposited on the fracture face. Concentrations of tilter cake can range from about 10 to greater than 25 times the surface polymer concentration depending on the formation permeability and fluids efficiency.
- North America > United States > Oklahoma (0.28)
- North America > United States > New Mexico (0.28)
- North America > United States > Wyoming > Greater Green River Basin > Almond Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Sugg Ranch Area > Canyon Sand Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Grayburg Formation (0.99)