High-permeability Reservoirs Research Articles

On the Effect of Mobile Oil Saturation On Fracturing Fluid Leakoff Characteristics In High-permeability Reservoirs

Abstract This paper presents the results of experiments and simulations conducted to investigate the effect of mobile oil saturation on the fracturing fluid leakoff characteristics under dynamic conditions in high permeability reservoir rocks. The fluid leakoff behaviour is examined for samples of varying permeability. In addition, the effectiveness of fluid loss additive in the presence of mobile oil saturation is investigated. A conceptually consistent model to predict the leakoff rate in the presence of mobile oil saturation at the fracture face has been developed. The model is validated using data obtained from dynamic leakoff tests. The results demonstrate that the presence of mobile oil saturation at the fracture face causes the leakoff characteristics to be very different from the tests for which the fracture face is completely saturated with brine. The leakoff characteristics are also affected by the fracture face permeability. Introduction In recent years, increasingly higher permeability formations are being hydraulically fractured (frac-pack) to overcome formation damage and/or prevent sand production problems(1–3). It is usually assumed that during initial stages of frac-pack treatments, a large amount of spurt loss occurs, which contributes to low fluid efficiency and high pumping cost(4). Spurt loss should be controlled in order to reduce the pumping cost and improve the economics of frac-pack treatments. Fluid loss additives are expected to reduce spurt loss by blocking the pore throats of the reservoir rock in the vicinity of the fracture face. In the design of fracturing fluid, the presence of oil in the reservoir which can significantly affect spurt loss and the performance of fluid loss additives, is usually ignored. Very few studies have been published on dynamic fracturing fluid leakoff behaviour in high permeability formation core samples. Further, the core samples in the available studies(4–6) were completely saturated with brine, in contrast to the in situ reservoir samples that have significant oil saturation. The effect of mobile oil saturation in the reservoir on the leakoff characteristics and quality of filter cake has rarely been addressed in the literature. The objective of the present study is to investigate the leakoff behaviour of fracturing fluids in the presence of mobile oil saturation. This objective is accomplished by conducting dynamic filtration experiments on core samples containing mobile oil saturation. A rigorous interpretation of these experiments involving cake build-up and multiphase flow is accomplished by using a mathematical model that incorporates the current understanding of the flow of non-Newtonian fluids, filtration and cake build-up, and multiphase flow in porous media(7). Experimental Setup and Procedures An experimental setup was designed and assembled for studying dynamic leakoff of fracturing fluids in the presence of mobile oil saturation. This setup is similar to the one used in an earlier study(7) except that the core holder is mounted horizontally. Experimental Setup Figure 1 illustrates the schematic of the experimental setup. A detailed description of the setup is presented by Gadiyar et al.(7) The major components of the flow system are: dynamic leakoff core holder, fluid displacement and pumping unit, pressure transducer manifold, and data acquisition system.

Evaluation and Selection of Drill-ln-Fluid Candidates To Minimize Formation Damage

Summary Conoco drilled and completed a horizontal well in a depleted, high-permeability oil reservoir. The formation is an unconsolidated, clean sandstone with absolute permeability over 3,300 md. The unconsolidated nature of the formation combined with its low pressure and high permeability caused concerns regarding hole stability, fracturing, excessive fluid loss, and differential sticking. To identify the best drill-in fluid (DIF) for the horizontal section, the evaluation of fluid candidates focused on both drilling properties and formation/completion-damage potential. The testing compared fluid performance in standard drilling-fluid tests, low-shear rheology at elevated temperature, dynamic fluid-loss behavior at elevated temperature, and core-flow tests. The flow testing was performed with cores from an offset well to simulate damage caused by DIF exposure and to evaluate remedial treatment options. Also, a new laboratory-scale procedure was developed to observe the tendency of prepacked screens to be plugged by DIF filter cake and unconsoli-dated formation sand. In addition to the laboratory testing, a review of the drilling and completion operations is presented, including performance of the drilling fluid at high overbalance pressure ( ≈ 2,600 psi) and the design and execution of subsequent remedial treatments. The production history is discussed and related to laboratory observations regarding cleanup and remedial-treatment effectiveness.

Underbalanced Drilling With Coiled Tubing: A Safe, Economical Method For Drilling And Completing Gas Wells

Abstract With the recent resurgence of the gas market and the continued commitment of the oil and gas industry to pursue safe, efficient and economical technology to stay competitive and viable, Underbalanced drilling with coiled Tubing is a natural progression for the 1990s and beyond. The successful marriage of conventional drilling technology with the obvious advantages of coiled tubing have brought about a new wave of economical gas wells which can be drilled and completed for a fraction of the cost of cased, cemented, perforated and stimulated wells. This study looks at coiled tubing drilling technology and its advantages. The methodology is discussed and case studies are examined. A peek into the development of this technology is offered and future developments are postulated. Why Drill Underbalanced? There have been many papers written over the years discussing formation damage and resultant loss of production and reserves. The debate over the subsequent ability to remove this formation damage via various stimulation and hydraulic fracturing techniques is a broad topic. However, all debate aside, if formation damage is avoided, or at least minimized from the outset, the technique used to eradicate the formation damage becomes a moot point. Hydraulic fracturing goes well beyond the scope of merely removing formation damage, but serves to increase effective drainage area and potentially tap into other permeability channels such as natural fracture conduits. However, in many areas where there is underlying water, the potential also exists to create a conduit into these zones and effectively negate the ability to produce the well. Barefoot Completions The increasing proliferation of barefoot completions is testament to the industry's push for more economical means of producing marginal gas reservoirs. One of the downsides to barefoot completions is the potential costs incurred by running and cementing casing and then finding that the reservoir is not economical to tie-in. This represents an increase in expenditure over "drill and abandon" costs. However, it has been this author's observation that when such a well is drilled, often considerable expense is incurred in running extra electric logs and testing. Casing is frequently run to attempt stimulation that will reduce potential formation damage. Setting casing above the zone of interest and then drilling into the zone underbalanced serves two main goals: First, formation damage is minimized and second, the well is production tested while being drilled. This serves to minimize the need for extensive formation evaluation and provides the means to cost effectively determine the merits of tieing in the well. Often high permeability reservoirs are subject to losses of circulation. Incremental costs in lost circulation material and additional rig time can be incurred and cementing difficulties are also probable. Setting casing above these zones can improve the probability of achieving a good cement job and can eliminate the costs and problems associated with a loss of circulation. Why Coiled Tubing? The next consideration involves the technique employed to drill the reservoir underbalanced. There are essentially three options to consider to complete a well underbalanced: drilling rig, service rig and coiled tubing rig.

Amphoteric Polymer Improves Hydrocarbon/Water Ratios in Producing Wells—An Indonesian Case Study

Summary Exorbitant water production is constantly burdening the oil industry, especially as lifting and facility costs rise and disposal of produced water becomes increasingly expensive and environmentally sensitive. An amphoteric polymer material (APM), previously described in Ref. 2, has been successfully applied in Indonesia. This product reduces water cut and very often increases hydrocarbon production by effectively reducing the permeability to water without significantly changing the formation permeability to hydrocarbons. This paper reviews the mechanism, application, and associated laboratory results by which the APM polymer reduces water cut, with a primary emphasis on Indonesian case histories. The product can successfully and economically reduce water production, often with the added benefit of increased hydrocarbon production. Results also indicate that high-permeability sandstone reservoirs with water-production problems can benefit from APM treatments. Laboratory and field results show good product application under high-shear situations and at temperatures up to 275°F.1,2,4 Careful candidate selection and good placement techniques, in conjunction with production logging to determine water location, are important to the success of APM jobs.

Recognition of Low Resistivity, High Permeability Reservoir Beds in the Travis Peak and Cotton Valley of East Texas : ABSTRACT

ABSTRACT Throughout East Texas, there are occurrences of unusually high-permeability beds in the Travis Peak and Cotton Valley Formations that have low resistivity even when charged with oil and gas. In most cases, these beds have retained primary porosity due to suppression of quartz cement by clay coatings that surround the grains in a conductive sheath. The clay-coated sandstones comprise a diagenetic facies that must be identified because commonly applied open hole well log analytical parameters cannot be used. The clay-coated grain facies is detectable with a cross plot of gamma ray and spontaneous potential overlain by resistivity. When gamma ray is plotted on the horizontal axis and spontaneous potential is plotted on the vertical axis, a triangular field of data points results. Data points that fall within the bounds of the triangle represent rock that has undergone normal diagenesis, is quartz cemented, and has low permeability. Data points outlying the hypotenuse represent uncemented beds with open pore throats and have high permeability. Outlying data points associated with resistivities of less than or equal to 1.5 ohm-meters are usually in the clay-coated grain facies. Zones flagged in this manner can be expected to have a cementation exponent in the range of 1.6 to 1.8, permeability in double-digit millidarcies, and be a potential low-resistivity pay.

Fracture Dimensions in Frac&pack Stimulation

Abstract A model is introduced to predict dynamic fracture dimensions in frac&pack stimulation. Design aspects of the two-in-one step treatment techniques, required by soft and high-permeability reservoirs are discussed. A pressure-dependent leakoff model, based on the transient flow of a non-Newtonian fluid displacing a reservoir fluid has been developed and incorporated with fracture mechanics concepts to simulate the entire process of frac&pack treatments including fracture propagation, inflation, proppant packing, and closure. Results obtained in this study indicate the considerable difference between traditional fracturing and frac&pack treatments. In the latter, fracture length is much less important than fracture conductivity. This work shows how to terminate the fracture growth at the appropriate time, and how to design frac&packs resulting in fracture widths several times larger than those for traditional fracturing.

High-Permeability Fracturing: The Evolution of a Technology

Abstract Since its introduction almost 50 years ago, hydraulic fracturing has been the prime engineering tool for improving well productivity, either bypassing near wellbore damage or actually stimulating performance. Historically (and in many instances erroneously) the emphasis for propped fracturing was on fracture penetration or length, culminating in massive treatments for tight gas sands using several million pounds of proppant with design 1/2 lengths in excess of 1500 feet (460 m). More recently, the importance of fracture conductivity has become appreciated. This has led to exciting "new" applications of propped fractures in better quality reservoirs as illustrated by North Sea wells, stimulations in Prudhoe Bay, and "frac-pack" operations in the Gulf of Mexico and Indonesia. While better understanding and new technologies are being used today, the actual application of fracturing to higher permeability formations is not new. During early development of fracturing, nearly all applications were for moderate to high permeability zones (since low permeability rock was of little interest at oil prices of $3/BBL). While tremendously successful at increasing PI, these early high permeability treatments were doing little more than bypassing damage. More recent development of improved, artificial proppant, cleaner fluid systems, and new technologies have changed this, making it possible to truly alter reservoir flow and stimulate production from moderate to high permeability reservoirs. The primary new tool in the engineers arsenal is the development of "tip screenout" fracturing. While higher permeability formations provide the "new" applications, the actual philosophy shift for fracturing occurred with the massive, tight gas stimulations. while outwardly a traditional, straight forward, application of fracturing to poor quality reservoirs, in actual fact these treatments represented the first engineering attempts to alter reservoir flow in the horizontal plane.

Exploration for Shallow, Compaction-Induced Gas Accumulations, Fort Union Formation, Powder River Basin, Wyoming: ABSTRACT

Commercial quantities of gas have been produced from shallow sandstone reservoirs of the Fort Union Formation (Paleocene) in the Powder River Basin of Wyoming. The two largest accumulations discovered to date, Oedekoven and Chan pools, were drilled on prospects which invoked differential compaction as a mechanism for gas entrapment and prospect delineation. Gas is believed to have accumulated in localized structural highs early in the burial history of lenticular sands. Structural relief is due to the compaction contrast between sand and stratigraphically-equivalent fine-grained sediments. A shallow Fort Union gas play was based on reports of shallow gas shows, the occurrence of thick coals which could have served as sources for bacterial gas, and the presence of lenticular sandstones which may have promoted the development of compaction structures early in the burial process, to which bacterial gas migrated. Five geologic elements related to compactional trap development were used to rank prospects. Drilling of the Oedekoven prospect, which possessed all prospect elements, led to the discovery of the Oedekoven Fort Union gas pool at a depth of 340 ft (104 m). The uncemented, very fine grained, well-sorted {open_quotes}Canyon sand{close_quotes} pay has extremely high intergranular porosity. Low drilling and completion costs associated withmore » shallow, high-permeability reservoirs, an abundance of subsurface control with which to delineate prospects, and existing gas-gathering systems make Fort Union sandstones attractive primary targets in shallow exploration efforts as well as secondary objectives in deeper drilling programs.« less

New Laboratory Procedures For Evaluation of Drilling Induced Formation Damage And Horizontal Well Performance

Abstract The popularity and breadth of application of horizontal well technology continues to expand. In some cases, however, horizontal well performance is disappointing - often as a result of drilling-induced formation damage. This damage may occur over the entire pay interval, or may occur in discreet intervals in varying degrees, depending on drilling conditions and changes in lithology along the wellbore. The resultant inflow may occur over one or more short segments rather than the entire horizontal wellbore. This limited drainage profile can lead to premature coning, and poorer than expected performance. Formation damage is normally modelled using a skin factor, s, in the Darcy flow equation, assumed to be a constant. The skin value used, if not measured directly from pressure transient analysis. can be based on laboratory regain permeability tests conducted on core samples, These tests involve comparing the final (regain) permeability, after mud damage during leakoff, to the initial undamaged permeability. The final regain permeability is typically measured at some arbitrary flow rate (and therefore. some arbitrary drawdown), Our research indicates that this test method is over-simplified because it does not recognize the ariable nature in which wellbore cleanup occurs. A more comprehensive test procedure has been developed for mud leakoff and regain permeability testing, whereby the regain permeability is measured at incrementally-increasing pressure differentials across the core. Imposing a pressure differential and measuring the resultant flow rate is consistent with applying a drawdown in the actual well. Application of the new test procedure with different drilling muds on several core plugs of varying permeability indicates that fluid inflow will not occur until a minimum "threshold pressure" is achieved" Lab results showed distinct differences in threshold pressure magnitude between different mud systems and rock permeability. Regain permeability improves with increasing pressure drop and with increasing volumetric throughput In some cases, it returns to its non-damaged value. A finite-difference wellbore simulator has been developed, incorporating the dynamic cleanup effect, to model early-time transient productivity in a horizontal well. The model predicts significantly poorer flow-contribution profiles than might be expected from the flow-capacity (kh) profile. The model also demonstrates how uneven wellbore cleanup is more likely to result in shorter effective well lengths in low-viscosity, high-permeability (high flow-capacity) reservoirs. In these reservoirs, where horizontal wells are often drilled for coning mitigation, shorter effective well lengths can lead to unexpected premature coning. Introduction Drilling-induced formation damage is recognized as a potential cause of lost well productivity(1). With horizontal wells, formation damage presents increased difficulties because:formation damage is often more severe(2)stimulation costs to overcome damage are high.assessment of well performance and identification of skin damage is difficult. Keelan and Koepf(1) emphasized the importance of performing core studies to evaluate formation damage prior to drilling. Several authors(l-8) used dynamic core-flow tests to characterize drilling fluid filtration behaviour, and to quantify damage caused by drilling mud following the filtration process. Marx and Rahman(4) emphasized the importance of performing core-flow tests at conditions that are close to borehole conditions.

Response of low-permeability, illitic sandstone to drilling and completion fluids

The effect of ion exchange and fluid flow on formation damage of reservoirs containing illitic clay minerals has been studied. Based on results of a number of novel experiments, a mechanistic description of the process of pore plugging by both clay particles and filtrate has been developed. The petrophysical properties of reservoirs containing illite depend significantly on the core preparation technique. Illite collapses upon air drying resulting in high porosity, high permeability and low capillary pressure. The illite rebounds, however, on contact with fresh water and projects across the pores, giving rise to low porosity, low permeability and high capillary pressure. Illite has also shown high susceptibility to migration: in fresh water it remains dispersed and is carried with the flowing fluid until the particles are trapped in pore restrictions. Above a critical salt concentration, however, the illite remains attached to the pore walls. A dynamic filtration of drilling fluid also indicates that an effective bridge (both external and internal filter cake) can be obtained by properly matching the particles of the drilling and completion fluids to the formation pores. This limits the invasion of solids to between 1 and 2 cm from the wall of the drilled hole. Polymers, however, can be carried deeper into the formation due to the filtration process. This study can be extended to medium- to high-permeability sandstone reservoirs which are also adversely affected by migration of fines and other particulates.

Monitoring and Analysis of Gravel-Packing Procedures To Explain Well Performance

Gravel-packed gas wells completed in the Gulf of Mexico since 1980 were reviewed to build a selective database for a completion-effectiveness study. Gas wells with clean, uniform sands were selected for analysis. Significant monitoring data identified were injectivity tests at different points during the completion and fluid loss rates (barrels per hour). Injectivity before gravel pacing and productivity after gravel pacing were classified according to sidewall-core permeabilities. Different gravel-pack preparation and execution techniques were reviewed. Fluid-loss-control pills were identified as the greatest source of damage restricting gravel-packed well productivity. Injectivity tests and sidewall-core permeabilities provide valuable information for monitoring well completion procedures.

Identifying Candidates for Horizontal Drilling Through Understanding Reservoir Heterogeneity: ABSTRACT

Horizontal drilling has proven to be a successful technology for exploiting unrecovered mobile oil in existing fields. Planning a successful horizontal drilling program requires a detailed understanding of reservoir heterogeneity while remembering that a horizontal well is basically a controlled, directional, completion technique. Also, in any reservoir being considered for horizontal drilling, heterogeneity has prevented the efficient and economic development of the pool by vertical wells. Reservoir heterogeneity can be of two basic types: operational and depositional. Operational heterogeneites are inherent in pool-producing practices such as coning or operator bias. Depositional heterogeneities compartmentalize the reservoir through some form of permeability anisotropy such as fractures or mud drapes. All reservoir complexities can be classified into either of these two major types or a combination of them. These two groups of complexities can be subdivided into 20 categories based on depositional architecture, hydrocarbon type, and reservoir drive mechanism. This system of classification simplifies the identification process.Heterogeneous high-permeability reservoirs with good vertical permeability make excellent horizontal drilling candidates. In general, low-permeability reservoirs do not make good candidates. Lithology also plays an important role in screening potential reservoir candidates for redevelopment using horizontal drilling. Top priority should be given to carbonates, lower priority tomore » sandstones, and lowest priority should be given to shales. The use of this classification scheme as illustrated can significantly improve overall performance and recovery efficiencies in most reservoirs.« less

Mathematical model of the dissociation of gas hydrates coexisting with ice in natural reservoirs

The dissociation of gas hydrate coexisting with ice in a low-temperature natural reservoir is investigated. A mathematical model of the process consisting of a generalization of the Stefan problem and containing two unknown moving phase transition boundaries — the hydrate dissociation and ice melting fronts — is constructed. It is shown that in high-permeability reservoirs the velocity of the dissociation surface is higher than that of the ice melting surface. As the permeability decreases, the fronts change places. The problem is solved in the self-similar approximation.

Tip Screenout Fracturing Applied to the Ravenspurn South Gas Field Development

Summary Tip screenout (TSO) fracturing is a means of creating greater propped fracture widths and hence fracture conductivities than can be achieved by conventional fracture treatments. This allows more cost-effective stimulations of higher-permeability reservoirs, especially where non-Darcy pressure losses are significant. This paper presents a procedure to design TSO schedules and reviews field results from the Ravenspurn South gas field, which was developed between 1988 and 1989. Evidence is provided to support the view that TSO pressure responses are indeed the result of processes occurring close to the fracture tip, rather than slurry-enhanced viscosity effects along the fracture length.

Regional Variation in Microscopic and Megascopic Reservoir Heterogeneity in the Smackover Formation, Southwest Alabama

ABSTRACT Quantitative (rank) measures of microscopic and megascopic reservoir heterogeneity are used to characterize the distribution of reservoir heterogeneity in Smackover hydrocarbon fields and wildcat wells in southwest Alabama. Microscopic reservoir heterogeneity (µH) is {[(0.25) + (meanlnK) + (1.5lnK)]/3}. Megascopic Heterogeneity (MH) is [(# of reservoir intervals) + (# of high-K reservoir intervals) + ( of # of reservoir intervals)] where reservoir rock is defined as exhibiting permeability values >= 0.1 md and high-permeability reservoir rock exhibits permeability values >= 1.0 md. Both MH and µH are determined from core data. The Dykstra-Parsons coefficient (DP) is a measure of microscopic heterogeneity that is partially independent of µH(r2 = 0.428). All three of these parameters are primarily measures of vertical heterogeneity, although averaging of wells within a field incorporates lateral heterogeneity in µH and DP. µH and MH are distributed in contrasting but related patterns. µH generally decreases from northwest to southeast, with the highest values found in the vicinity of the Choctaw Ridge complex north of the Mississippi Interior Salt Basin (MISB). Moderately high values typify the Manila Embayment and the Conecuh Ridge complex to the south, whereas lower values are found in the MISB, on the north flank of the Wiggins Arch, and in the Conecuh Embayment. µH values are high in the Moldic Pore Facies and low in the Intercrystalline Pore Facies. The distribution of MH is roughly opposite to that of µH. MH values are high on the north flank of the Wiggins Arch, on the Conecuh Ridge complex and in the Conecuh Embayment: MH values are low near the Choctaw Ridge complex. The Conecuh Ridge is unique because it is characterized by high values of both µH and MH. Also, the low-relief north-south trending salt-cored anticline in western Washington County is characterized by relatively high values of MH. Reservoirs belonging to the Moldic Pore Facies tend to be homogeneous with respect to MH, whereas reservoirs assigned to the Intercrystalline Pore Facies are characterized by relatively high values of MH. MH and µH vary congruently with pore-system characteristics (controlled by depositional patterns, dissolution, and dolomitization) and regional structural and paleogeographic trends. This suggests that reservoir heterogeneity characteristics are controlled by structural and paleogeographic setting, by depositional fabric, and by diagenesis. However, because contours of µH and MH are approximately normal to structure contours but parallel to Smackover thickness contours, it appears that depositional setting (or paleogeography) influenced reservoir heterogeneity more than did structural evolution. The distribution of DP values is not related to pore-facies distribution. Thus we conclude that DP is less useful for regional heterogeneity studies than is MH or µH.

Factors Controlling the Distribution of Reservoir Quality in the Pennsylvanian Bend Conglomerate Fan-Delta System

Chert conglomerates, and associated sediments, of the Bend Conglomerate in Taylor Draw field, Upton Co., Texas, were deposited in a series of fan deltas that prograded into an open-marine system. The distribution of reservoir quality in these deposits is facies controlled. Permeabilities range from near zero to 30,000 md. Low-permeability conglomerates contain either a mud matrix or abundant calcite fossil fragments. The calcite grains serve as nucleation sites for calcite cementation and, through dissolution, as a source of calcite cement. High-permeability, sandy (chert and quartz) conglomerates have no mud matrix or calcite grains. Some of them are cemented with a thin rim of chalcedony, while others have no cement and show strong pressure solution at grain contacts. They are commonly friable and are recovered as loose gravels in the core barrel. The mineralogy of matrix gains is related to the distribution of the depositional facies within the fan delta. The low-permeability conglomerates were deposited in the subaerial to subaqueous distal fan-delta complex where calcareous marine organisms or mud were mixed with the conglomerate. The high-permeability conglomerates were deposited as thick channel-gravels in the subaerial proximal and mid-fan sections of the fan deltas. Depositional facies within the fan-delta complex controlled themore » distribution of calcite grains in the matrix and hence reservoir quality. The fossiliferous conglomerates became tightly cemented with calcite during burial, whereas the nonfossiliferous conglomerates remained permeable. Facies maps of the fan-delta complex therefore can be used to delineate high-permeability conglomeratic reservoirs.« less

The Use Of Pressure Build-Up Data In Pressure Transient Testing

Introduction Over the past decade, the petroleum literature has been deluged by a seemingly endless variety of well test analysis techniques. Although some developments have occurred as refinements to the fundamental flow relationships, most have arisen from better models and more complex boundary conditions and flow geometries. Early on in the literature, steady state concepts were deemed adequate(1); apparently because of simple radial flow geometries, high permeability and strong reservoir drive mechanisms coupled with the use of pressure gauges with low resolution capacities. Gradually unsteady state techniques were introduced and graphical techniques evolved(2) to establish formation capacity, reservoir damage, etc. Today the well test analysts can be found working in conjunction with production engineers, drilling and completion engineers, reservoir engineers and explorationists alike. Recent developments in bottomhole pressure gauges with higher pressure resolving capabilities and the availability of computer resources have facilitated increasingly sophisticated pressure analysis techniques and yet very little has been written on how to collectively incorporate these new techniques into a unified and practical method of pressure transient analysis. It is the intent of this paper to provide one approach found to be very successful for analyzing the tests encountered. Also demonstrated is the use of pseudo pressure, pseudo time and a general method to correct build-up data for use with drawdown type curves. Although the focus is primarily on build-up analysis after a constant rate drawdown, the extension of these techniques to other types of analysis is obvious. A Unified Approach The plot of the logarithm of pressure, or pressure function, vs the logarithm of time, or time function, forms the basis of this technique (commonly referred to as the log-log plot). Because the axes of a log-log plot are of fixed dimensions relative to each other, the analyst has a standard frame of reference by which all times may be compared regardless of pressure behaviour. This facilitates quick qualitative assessment of the test through repeated pattern recognition developed through experience.High precision gauges have allowed the development of pressure derivative techniques(3) which greatly enhance qualitative test analysis due to the derivative's high sensitivity to changes in flow geometry. Further developments by Bourdet et al. (4) combined the pressure derivative response with the log-log plot to reduced the uniqueness of match to a limited number of alternatives within the scope and span of the data. Other advantages are the independence of the pressure derivative response to the initial shut-in pressure and the simple mannerin which pure flow geometries occur as straight lines. The conventional plots (plots of a pressure function vs a time function) can use data delineated by observing the pressure derivative response on the log-log plot to verify the well test interpretation. The authors do not endorse the approach of using the pressure and pressure derivative log-log plot alone to complete the analysis. The strength of the unified approach is the existence of consistency cross-checks between different methodologies to improve the quality of the answer. This reduces the uncertainties when type curve matching or conventional techniques are used independently.

The Technical and Economic Feasibility of Enhanced Gas Recovery in the Eugene Island Field by Use of the Coproduction Technique

Summary. Coproduction, the simultaneous production of gas and water, is used to control water influx into water-drive gas reservoirs. The coproduction technique can increase gas recovery by as much as 20%. Reservoir selection criteria and study methodology are presented and illustrated with a U.S. gulf coast reservoir. Basic material-balance analysis, tank-model simulation, and a preliminary economic analysis demonstrated the technical and economic preliminary economic analysis demonstrated the technical and economic feasibility of the process for a case study of the Louisiana gulf coast Eugene Island Block 305 10,300-ft [3140-m] -sand gas reservoir. This study also shows that the coproduction technique could result in a substantial increase in recovery efficiencies in many other water-drive gas reservoirs under specific economic conditions. Introduction Conventional production in a water-drive gas reservoir terminates when the producing wells load up with water, leaving high-pressure bypassed gas in the watered-out areas and in the gas cap updip of the watered-out wells. Generally, recovery from water-drive gas reservoirs is much lower than that from depletion-type gas reservoirs. Water-drive gas reservoirs generally have much lower recoveries than depletion-drive reservoirs. In a water-drive gas reservoir, the reservoir pressure is maintained by the encroaching water. The stronger the water drive, the higher the reservoir pressure remains. Because residual gas saturation is independent of pressure, larger amounts of gas (residual gas) are trapped at the higher pressure than if a lower stabilization pressure could be pressure than if a lower stabilization pressure could be reached. An existing technique that would benefit recovery in these strong water-drive gas reservoirs is the accelerated blowdown method. In essence, the concept is to out-run the water influx by producing gas at accelerated rates. Reservoir pressure is reduced before the aquifer can respond fully. Usefulness of the process, however, is limited in many cases. Deliverability controls because of sales contracts or production facilities may disallow high production rates. High-permeability reservoirs show production rates. High-permeability reservoirs show dampened efficiencies as a result of high water mobility. Reservoirs with considerable permeability variations show a reduced effectiveness of the method because of the uneven advancement of water. Water-coning and wellsanding problems may cause many operational problems. Often the scale of economic investment required problems. Often the scale of economic investment required to implement this process defers application. In the proposed coproduction process, as the downdip wells begin to water out, they are converted to high-rate water producers, while the updip gas wells maintain gas production. The coproduction process enhances recovery production. The coproduction process enhances recovery in three ways:production of water lowers reservoir pressure, and more gas is produced because of expansion; pressure, and more gas is produced because of expansion;water production slows the advance of the water front; andpreviously immobile gas in the swept zone might become mobile again as the pressure is lowered. The process is applicable in all moderate-to-active water-drive gas process is applicable in all moderate-to-active water-drive gas reservoirs. Reservoirs not yet watered out, however, present the greatest economic potential. present the greatest economic potential. Coproduction Technique The coproduction process is defined as the simultaneous production of gas and water. Initial attempts of enhanced production of gas and water. Initial attempts of enhanced gas recovery by coproduction focused on the depressurization of a totally watered-out reservoir by withdrawing large volumes of water. This process is technically feasible and economically applicable in some cases. In the case of unfavorable gas relative-permeability characteristics, however, extremely large volumes of water must be removed to mobilize the gas. Also, the cost involved to rework a shut-in field and to handle large amounts of two-phase gas and water production at high water/gas ratios might be prohibitive. Our study directs the application of the process to waterdrive gas reservoirs not yet totally watered out. The process involves the conversion of downdip wells to water producers as they water out, while gas production updip producers as they water out, while gas production updip is maintained. The production of downdip water enhances recovery by (1) slowing the advance of the water front, thus delaying the watering out of wells, (2) reducing reservoir pressure so more gas can expand and be produced, and (3) reducing pressure in the swept zone so that previously immobile gas can expand and perhaps be produced. previously immobile gas can expand and perhaps be produced. The updip gas wells can, if warranted, be produced at a high rate, thus incorporating the benefits of the accelerated blowdown method. JPT P. 585

Pressure-Derivative Approach to Transient Test Analysis: A High-Permeability North Sea Reservoir Example (includes associated papers 15270 and 15320 )

Summary A recently developed method of transient test analysis, which uses the derivative of pressure data vs. time rather than the pressure/time data alone, is discussed in general terms with regard to its application to very-high-permeability reservoirs. The extension of this method to the various well/reservoir system models considered by several authors is summarized. The procedure involves the combined use of existing type curves in both the conventional dimensionless pressure form (PD) and the new dimensionless pressure pressure form (PD) and the new dimensionless pressure derivative grouping ( ). The procedure proved theoretically and through examination of data from the Oseberg field to be a powerful tool in transient test analysis. The identification and powerful tool in transient test analysis. The identification and interpretation of reservoir heterogeneities, both linear and dispersed, as well as earth tidal effects, which are often not easily discemible through existing methods, are greatly facilitated by the new method. Introduction The interpretation of transient test data is the main source of information on the dynamic behavior of a reservoir, expecially if permeability is high, because a test can investigate an appreciable volume of the formation. In recent years, the science of transient well test interpretation has progressed rapidly, most notably through the increased use of type curves, the introduction of new reservoir models, and the advent of computer interpretation packages. These advances greatly augmented the conventional analysis approaches that are based on the homogeneous reservoir system and manual, graphical methods. However, many engineers still have reservations about the usefulness of type curves and the reliability of test information from anything but the simplest responses. Improvements in well-testing techniques-especially the introduction of the latest generation of electronic bottomhole pressure (BHP) transducers and recorders have dramatically improved data quality and, consequently, the amount of information that can be obtained from test analysis. An analysis method that deals directly with rate of pressure change, rather than absolute pressures, greatly pressure change, rather than absolute pressures, greatly simplifies the main problems of interpretation, model diagnosis, and evaluation of parameters. Consequently, much more confidence can be placed in the results obtained with the derivative approach. This paper covers extensions of the derivative approach to various models proposed by different authors. its application to high-permeability >1 darcy) reservoirs is demonstrated. All previous work on the subject has been confined to reservoirs with permeabilities less than 100 md. Field examples are used to illustrate tile application's validity. Interpretation of Transient Tests Traditional and Derivative Theory. Practical transient test interpretation methods have become polarized in recent years between two analysis techniques - conventional and global. The former basically consists of fitting straight lines to data regions (for example, in the Homer analysis) or their multirate extensions or superpositions (see Appendix A). The latter involves the use of various type curves to include the entire data set in the process of reservoir/well system diagnosis. Flow-regime identification, and evaluation of system parameters. It is commonly accepted that great confidence in interpreted results is obtained by an iterative combination of the two techniques that starts with the global approach. The recently documented pressure-derivative approach has combined the most powerful aspects of the two previously distinct methods into a single-stage interpretative plot. The most useful traditional type curves depict, on a log-log scale, the evolution of the dimensionless pressure, PD, with the dimensionless time group pressure, PD, with the dimensionless time group. For the basic, most common model of a well with wellbore storage and skin in a homogeneous reservoir, the individual curves are dependent on the wellbore condition group. These type curves have two main drawbacks, especially when associated with high-permeability reservoirs. First, there is the uniqueness of the diagnosis. The various curves have similar shapes, particularly when the effect of wellbore storage is very short-lived, as in the highly permeable Oseberg field. JPT p. 2023

Analytical and Numerical Modeling of Immiscible Gravity-Stable Gas Injection Into Stratified Reservoirs

Abstract A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model. Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil. A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids. Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process.