Tight formations are being developed by drilling in the Midland Basin. Target intervals include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet true vertical depth (TVD). Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the expected pay intervals and are produced commingled. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data pose challenges to making the best decisions. Numerical models can yield insights about drainage patterns and potential interference. This paper reports a case study using a geologic model, hydraulic stimulation models, and a reservoir simulation model to evaluate reduced well spacing impacts on recovered oil and economics. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to data constraints. A reservoir simulation model was then utilized on a sector area of the full model. The sector model was history-matched to early production data and historical type curves. Each well had 10–12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. The paper presents history-matched simulation models that were executed to predict production and economics for 40-acre and 20-acre well spacing cases.

The application of NMR methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids which can be in liquid, gaseous or adsorbed phase in nanometer size pores (associated with various minerals and organic matter) add another degree of complexity to the interpretation of NMR data in shales. This report presents the findings of a laboratory study on the NMR responses of brine, oil and methane in shales. The acquisition of the NMR data was made at 2MHz. NMR T 2 distributions were acquired at TE = 0.2ms on companion core plugs from the Haynesville shale and at TE = 0.3ms for Barnett and Woodford shale samples. The NMR T 2 distributions acquisitions were conducted on samples saturated with brine (2.5% KCl) and oil (dodecane). The NMR T 2 data acquired on the native state samples (as received) showed a bimodal distribution with the dominant peak at T 2 less or equal to 1ms. After saturation in parallel with oil and brine with increasing saturation pressures we observed in the case of brine an increase in amplitude of the NMR peak located at T 2 less or equal to 1ms. At higher saturation pressures we observed a shift in the T 2 time of this peak toward longer T 2 times. When the samples were saturated with oil and the saturation pressure increased we observed the development of second NMR T 2 peaks around 6-20 ms with no substantial increase of the peaks at T 2 less than 1ms; the observed distributions are bimodal. The measurements with methane were conducted at TE = 0.3ms on 2 Haynesville core plugs at a methane pressure of 4000 psi and a confining pressure of 5000psi. The NMR T 2 distributions that were essentially unimodal in the as received state with a peak at 0.35-0.4ms, evolved into a bimodal distribution in response to the injection of methane. The first peak was observed at the same T 2 time as in the as received state with no substantial change in amplitude and second peak was located at 10-20ms ms. This results show that the NMR response of methane and oil is similar. Monitoring the saturations increase with NMR show that brine can enter the entire pores spectrum while oil and methane have access only to a fraction of the pore space.

Oil shale, an organic-rich impermeable rock, is an abundant energy resource in the United States. Because few oil shale deposits occur in shallow formations, application of an in-situ process is necessary for thermal decomposition and subsequent oil and gas production. An earlier investigation indicated that cylindrical or planar in-situ electric heaters were more efficient than flowing steam through created fractures. This study investigates the efficiency of oil shale in-situ upgrading by steam flowing in vertical fractures. There are challenges in the through description of in-situ upgrading process because the kerogen decomposition involves of a series of complex and sensitive reactions, and results a large number of fluid and solid products. Expanding the Flow and Transport Simulator (FTSim) developed by Texas A&M University, we developed a fully implicit capability that describes the decomposition of kerogen in the oil shale and the resulting system changes with minimal simplification and assumptions. The decomposition process is represented by 6 kinetic reactions (resulting 10 components and 4 phases), involves coupled processes of mass transport and heat flow, and accurately accounts for phase equilibrium and phase transition thermodynamics. We applied our simulator to find a successful strategy for hydrocarbon production using steam that flows in vertical fractures created by multistage transverse fracturing in a horizontal (MTFH) well. The simulation of simultaneous heating and flowing provides the system change of oil shale reservoir during in-situ upgrading, and it indicates the necessary condition of successful hydrocarbon production from oil shale reservoir.

Horizontal wells with multistage hydraulic fracturing stimulation become the common practice in developing tight and shale gas reservoirs. For gas condensate reservoirs, heavier components in the gas phase start dropping and decrease the gas mobility due to a relative-permeability relationship as reservoir pressure drops below the saturation pressure. Therefore, modeling the condensate banking along hydraulic fractures becomes critical in understanding the productivity loss, the hydraulic fracturing job design as well as the field production optimization. In addition, along with pressure depletion, the stress dependent permeability must be taken into account either by an approximation derived from lab experiments inside a finite difference flow simulator or modeling separately by a finite element geomechanics code. A condensate fluid pseudoization that reduces nine hydrocarbon components to a pseudo three components mixture is presented in this paper. The control volume based multiphase multi-components thermal simulator FATS is utilized in modeling the condensate banking inside the hydraulic fractures and surrounding matrix blocks. A K-value interpolation algorithm is developed and validated by a two-phase envelope generated by an Equation of State (EOS). FATS results are validated by the EOS based reservoir simulator GEM. A compositional simulation model is coupled with reservoir geomechanics in this study to investigate the interaction of stress changes and its effects on multiphase flow along fractures. A modular coupled approach is implemented for solving the stress and flow equations at each time step by the iteration between the reservoir simulator and geomechanical module. Pressure and temperature changes occurring in the reservoir simulator are passed to the geomechanical simulator to compute the changing of stress and strain and updating porosity and permeability simultaneously. Simulation results show that fracture conductivity reduction is due to the combination of condensate banking and changing of the effective stress along hydraulic fractures.

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

The United States Geologic Survey (USGS) reported in 2008 that undiscovered technically recoverable oil in the Bakken was about 3.6 billion barrels across the U.S. portion of the basin, considering recent successful application of horizontal wells and multistage hydraulic fracturing technologies. As the development of the unconventional resources in the Williston Basin continues beyond the phases of exploration and lease evaluation, optimum well spacing and recovery factor will become forefront considerations in the formulation of asset development strategies. Based on our studies the reservoir producing mechanism is primarily solution gas drive and primary oil recovery factor is lower than 15% of the original oil in-place. This low recovery or very high oil volume remaining in place is a strong motivation to investigate the application of enhanced oil recovery methods in this basin. This paper describes the construction of numerical simulation models using typical fluid and rock properties for the Bakken and Three Forks, assuming both naturally fractured and single porosity systems and their combinations. Multistage hydraulic fracture properties are determined from well completion engineering and coupled with the flow models. The flow models are constrained by well operating practices implemented by operators across the basin during primary oil production. The results of pressure maintenance methods to arrest the rapid reservoir pressure decline due to large pressure drawdown necessary to produce oil and water, as well as gas (including carbon dioxide) and water injection methods to improve oil recovery are presented.

Effect of retardation in fluid displacement on transport inside capillary tubes during leak-off and clean-up for hydraulically stimulated reservoirs is investigated by modeling of the relevant phenomena. The effect of wall proximity during the transport in narrow capillaries is formulated. The importance of the critical properties alteration due to confinement is demonstrated by modification of the real gas deviation factor. The relaxation in fluid displacement observed in the fluid transport dynamics is coupled with the bundle of tubes representation of porous media for investigation of the relaxation effects on fluid saturation, capillary pressure, and relative permeability. An analytical formulation of the relaxation time corresponding to water removal during clean-up processes following hydraulic fracture stimulation is presented. The dynamics of advancement of the wetting and non-wetting fluids inside capillary tubes are illustrated by various applications.

The necessary and sufficient conditions of the design parameters that should be considered to build proper shale-gas reservoir simulators are investigated. The design requirements are established based on the theoretical studies of flow through extremely low permeability porous media, ion milled SEM images of the nano-geometry of shale-gas reservoir formations, laboratory petrophysical measurements, and the available production and stimulation information. This paper presents a critical discussion of the relevant aspects such as the reservoir formation structure, fluid storage and transport mechanisms, and gradual non-equilibrium motion and dynamic distribution of fluids in the pore system. Then, an overview of the capabilities of the commonly used reservoir simulation software is presented in view of the identified requirements of shale gas reservoirs. Quantitative comparisons between the alternative formulations against the conventional formulations are also presented with several examples using an in-house simulator developed in this study. Areas needing new fundamental formulations and further research for proper shale-gas reservoir modeling are delineated. This paper provides important insights and guidelines for development of adequate numerical simulators that can correctly accommodate for the proper description of the relevant phenomena, and predict gas production and water displacement in shale-gas reservoirs.

The problem of condensate blocking in low permeability gas-condensate reservoirs is greatly affected by the rock-fluid interactions and capillary trapping. Many publications suggest wettability alteration to gas-wetting as a permanent solution to the problem. In this work, we present a simulation study on the optimum wettability conditions for maximum gas-condensate well productivity enhancement. Most of the work in this area focuses on reversal of wetting conditions from liquid-wetting (contact angle of 0 degree) to gas-wetting (with contact angle around 150 degrees). On the experimental side, chemicals are tested in its ability to change wettability. On the simulation side, research shows that changing the wettability to gas-wetting in the near wellbore region results in better productivity than the original liquid-wetting state. Our work investigates various states of wettability ranging from liquid-wetting to gas-wetting and its effect on gas-condensate well productivity. We also study the effect of reservoir permeability, reservoir pressure and treatment radius on the well productivity enhancement by wettability alteration.

We present a practical assessment of petrophysical properties of shales and their measurement in the lab and via logs. Gasbearing shale present unique measurement challenges due to their ultra-low permeability and complicated pore volume connectivity. The combination of low intrinsic permeability and gas sorption effects renders these reservoirs "unconventional". Advances in horizontal drilling and hydraulic stimulation have transformed gas-shale resources into economic reserves. Given their economic significance, there is a strong drive to understand gas shale petrophysical property measurements, both in the laboratory and in the subsurface. We note that various core analysis protocols are used in different laboratories leading to physical property measurements that are inconsistent, even when measured on identical sample sets. In addition, log analysis of kerogen-rich shale is ‘unconventional’ compared to classical techniques used in tight gas sands. As shale gas evaluation is becoming widely practiced among service companies and operators, we will focus on three reservoir assessment categories: storage capacity (gas-in-place), flow capacity (gas deliverability) and mechanical properties impacting hydraulic stimulation. Within each of these categories we have identified influential petrophysical properties such as rock composition, total organic carbon (TOC) content, porosity, saturation, permeability and mechanical properties. Specifically, we demonstrate the importance of estimating accurate mineral and kerogen content as these properties directly impact rock quality, hydraulic fracturing protocols, and gas-in-place estimations. In reviewing these practices, we also will show the need and possible direction of new technologies that will be required for making evaluations more accurate and quantitative in the future.

The current paper complements the Moridis et al. (2009a) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas hydrate petroleum system, to discuss advances, requirement and suggested practices in gas hydrate prospecting and GH deposit characterization, and to review the associated technical, economic and environmental challenges and uncertainties, including: the accurate assessment of producible fractions of the GH resource, the development of methodologies for identifying suitable production targets, the sampling of hydrate-bearing sediments and sample analysis, the analysis and interpretation of geophysical surveys of GH reservoirs, well testing methods and interpretation of the results, geomechanical and reservoir/well stability concerns, well design, operation and installation, field operations and extending production beyond sand-dominated GH reservoirs, monitoring production and geomechanical stability, laboratory investigations, fundamental knowledge of hydrate behavior, the economics of commercial gas production from hydrates, and the associated environmental concerns.

Abstract New methodology (cubic cores) of studying fractured carbonate reservoirs is presented in this paper. Several examples of Russian carbonate reservoirs are given including: Orenburg Gas-Condensate Field, Urmansk Oilfield and Vuktyl'skiy Gas-Condensate Field. A correlation between porosity and permeability was established, which is of vital importance in carbonate reservoir rock characterization. On considering two additional variables (irreducible fluid I saturation and specific surface area, which is a measure of degree of fracturing), very good correlation was obtained between porosity and permeability. Without considering these two variables, the coefficient of correlation is commonly very low.

ABSTRACT A number of laboratory studies on coalbed methane (CBM) have provided data for the relative permeability of coal to gas and water, which are needed to analyze CBM reservoirs, particularly in numerical simulation. The relative permeability curves of coal to gas and water are determined using the two methods used in the petroleum reservoir engineering, namely, the steady or unsteady state displacement methods. In most cases, the unsteady state displacement method is used because this method is relatively fast to carry out. In this method, the non-wetting fluid is displaced by the wetting fluid, and the effluent production and pressure history are used to back out the relative permeability of coal to gas and water. One of the problems encountered in the displacement methods is the question of coal wettability. Many researchers studying this area have considered that coal is water-wet. However, it is a well-known fact that a large amount as much as 95% of methane is adsorbed on the internal surface of coal matrix. Therefore, coal could be regarded at least as initially gas-wet. The wettability of coal will depend on the flow characteristics of coal, that is, whether methane flows in the matrix. This paper investigates a number of wettability of coal scenarios and discusses the approaches used by various investigators, for instance, pre-heating the coal sample before any testing, and using a non-adsorbable gas, pointing out their limitations from the viewpoint of CBM reservoir simulation. The likely dependence of relative permeability of coal on flow pressure is also addressed. INTRODUCTION The earliest studies in numerical simulation of CBM date back to 1970's (Price and Abdalla, 1972). At the time, the principal objective was degasification of coal seams for mine safety to keep coal mining safe from explosions rather than CBM production to use as an unconventional gas resource. Since then, there has been continued research in CBM simulation as most of the simulators used for CBM production were often based on conventional (sandstone) reservoir models that have been modified to accommodate coal properties. In recent years, advanced simulators that are specific to CBM reservoirs have been developed to incorporate CBM reservoir parameters such as the relative permeability, which controls the well and the reservoir performance. The objective of this paper is to examine the past relative permeability measurement studies and identify problems posed by coal compared to typical reservoir rocks such as sandstone and carbonates. WHAT IS COALBED METHANE? Coal is "the black rock that burns" (Land and Rice, 1993). It is defined as a readily combustible rock that contains more than 50% by weight and more than 70% by volume of carbonaceous material including inherent moisture formed by compaction and induration (hardening of sediment) of various altered plant remains. The type of plant materials, degree of metamorphism, and the range of impurity characterize coal (Bates and Jackson, 1980). A coal seam is a bed of coal, and the natural gas or methane produced from coal seams is referred to as coalbed methane (CBM).

Abstract A study was carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells. At the gas velocities normally encountered in hydraulic fracture proppant packs, non-Darcy pressure drops dominate, and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of: Gas velocity (hence: rate and flowing pressure) Ratio of free liquid rate to gas rate Stress on the proppant Type of proppant Thus, apparent proppant permeability will vary with distance from the wellbore, increasing towards the tip of the fracture where liquid ratio and velocity are lower. This variation of permeability was explicitly modeled in the proppant pack by dividing it into segments and calculating the permeability in each segment. As a result of this modeling, the impact of increased fracture length on productivity was found to be more significant than in simpler modeling where one permeability value is used for the entire proppant pack. The variation of apparent proppant permeability along the length of the fracture and its impact on well productivity are discussed in this paper. A comparison of predicted well productivity is also made with the use of a constant permeability value for the proppant in numerical and analytic simulators. We will show that using a constant proppant permeability value results in an estimate of optimal fracture length that is too short. Introduction A numerical simulator was used to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir. The fracture was explicitly modeled as a set of high-conductivity cells. The impact of condensate dropout was modeled in both the reservoir and the proppant pack. To model the pressure drop in the reservoir rock with a vertical un-fractured well, a set of relative permeability curves and the rock beta factor were adequate. In the rock adjacent to the propped fracture, the gas velocities are low because of the much greater flow area---two orders of magnitude lower than those around a wellbore, and non-Darcy flow is not an issue. In the proppant pack, however, the high velocity of gas and the presence of liquid means that the apparent permeability of the proppant is a function of gas velocity and ratio of free liquid rate to gas rate. These are in addition to the other factors that determine proppant conductivity in single-phase flow:stress on the proppant and type of proppant. Thus, apparent proppant permeability will vary with distance from the wellbore, increasing towards the tip of the fracture where both the liquid-to-gas ratio and the velocity decrease. This variation of permeability was explicitly modeled in the proppant pack by dividing the fracture into segments and calculating the permeability in each segment.

Abstract To exploit the substantial tight-gas resources worldwide, hydraulic fracturing is, for many cases, economically a viable option. However, despite the state of the art techniques such as multiple fracturing of horizontal wellbores, the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality, strong stress dependency in permeability, hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one, related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics, was rarely taken into account before and is the subject of the current paper. For this purpose, an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator, capturing the yield stress of common polymer gel. The model is applied to typical cleanup scenarios. Using the model, it can be shown that the residing, non-recoverable gel (typically 50%) decreases the fracture conductivity and, hence, the production potential of a fractured gas well. This coincides with experiences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fracture, gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in analytical studies, there is no sharp interface between the residual gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of fracture cleanup processes and, hence, an improved understanding of formation damage processes in fractured wells. Furthermore, the model enables the design of more successful fracture treatments in tight-gas reservoirs. Introduction Evaluation of postfracture performance has been the subject of extensive investigations over the past decades. For hydraulically fractured gas wells, a number of potential damage mechanisms were identified, such as hydraulic damage caused by invading fluids during the treatment and damage due to the stresses exerted on the fracture face. In addition, damage to proppant pack, reducing the conductivity and the associated non-Darcy flow effects which cause additional inertial pressure drops, were also attributed as causes of possible productivity impairment. However, these effects are not solely responsible for potential productivity impairment in tight-gas reservoirs. Many tight-gas wells do not respond to hydraulic fracturing as expected. Following the fracturing treatment, a typical tight-gas well achieves its maximum gas rate within a few days after stimulation and then experiences a rapid production decline. Some tight-gas wells, in contrast, do not show such obvious production peaks but instead sustain a flat production profile or exhibit a slowly increasing production rate for several weeks or months.[1] A major potential reason for this behaviour given in previous studies was the fracturing fluid. Commonly, cross-linked polymers facilitate hydraulic fracturing treatments, the intent being that the polymer will be recovered once production is initiated. In the field, only a fraction of the injected polymer can be produced during the cleanup process, typically up to 50%. Slugs of unbroken residuals were reported during the post-fracture production and indicate the existence of gel residues inside the fracture after the cleanup process. The incomplete degradation of the polymers in the fracturing fluid results in productivity impairments due to formation and proppant pack permeability reduction. Fracturing fluid issues are suspected to contribute to the discrepancy of effective and propped fracture half-lengths with fracture conductivities commonly much lower than anticipated.

Abstract Sour gas reservoirs with high content of sulfur are distributed widely around the world. Solid elemental sulfur which dissolves in the gas phase originally in the reservoir, may deposit when the thermodynamic conditions of the temperature, pressure or composition changes in the process of production. Deposition of solid elemental sulfur may block the pores in the formation and significantly affect the gas deliverability. In this paper, sulfur deposition mechanism is analyzed in the reservoirs. Based on the characteristics of sulfur deposition in the formation, a corrected function is introduced to modify the gas flow. Then, an evaluation method of the effect of sulfur deposition on gas deliverability is presented. For a practical sour gas reservoir, the gas deliverability considering sulfur deposition in formation is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the physical parameters in the formation on which the gas well is located. Introduction Because of the high content of sulfur, especially when the concentration of H2S is high in the reservoir fluid, the critical production technology is required. Reduction of pressure and temperature of reservoir which reduces the solubility of sulfur in sour gas will cause sulfur to deposit in the reservoir. Deposition of sulfur within reservoir rocks can impair porosity and permeability and results in the decline in gas productivity and thus affects economic feasibility negatively. Many of the operational and reservoir parameters influence sulfur deposition. A theoretical research was studied by Kuo[2] on investigating the effect of the deposition of immobile elemental sulfur from a homogeneous reservoir. Sulfur deposition in the formation was attributed to the decline in production from a well producing from a dry, sour (16% H2S) gas pool operated by Shell Canada Limited located in the Waterton gas field of south-west Alberta, Canada. Sour gas reservoirs with large amount of hydrogen sulfide, 7.13%-10.49% (102.07–196.57g/m3), Sulfur are found and developed in recent years in China, such as gas reservoir of Fei Xian Guan, Luo Jia Zai, located in Sichuan province. The distribution of sulfur in a core is illustrated in Fig.1.[1] In this paper, the focus is on the prediction of deposition of sulfur and reduction of gas productivity in order to assess the impact of sulfur deposition on inflow performance.

Abstract Well test analysis techniques use variations of the pseudopressure concept to account for multiphase effects due to condensate drop-out in near-well regions (e.g. Jones and Raghavan[1] approach). In this work, an evaluation of the accuracy and applicability of these techniques was carried out using data from the discovery well of the Cupiagua field, including well testing, relative permeabilities (Kr) measured at low capillary number and a tuned PREOS. Henderson et al's capillary number dependent relative permeability and effective inertial resistance correlations,[2] as implemented in a commercial simulator, were used to history match the well test data. To investigate the assumptions in the analytical models, numerical simulations were run, first with constant Kr, and then with the effect of capillary number and inertial resistance. The main conclusions are: For the constant Kr simulation, a constant composition expansion (CCE) data of the flowing composition accurately reproduces the pressure-saturation relationship in the region where both oil and gas are mobile. However, contrary to Fevang and Whitson's assumption,[3] the constant volume depletion (CVD) data did not match the saturation distribution of the region where only gas flows. When Kr dependence on capillary number and inertial resistance was considered, the immobile oil region practically disappeared. In consequence, the CCE data of the original fluid composition can reproduce the pressure-saturation relationship in the two phase region. Al-Hussainy et al's total skin versus rate plots[4] to obtain mechanical skin figures were found to give results similar to those obtained by numerical simulation. In summary, this work identifies clearly the conditions under which the analytical models are not correct, which data should be used for analysis, and when the numerical instead of an analytical approach is required. Introduction Planning of operations aimed to increase well deliverability by decreasing formation damage or stimulating the formation, relies on the accurate estimation of contributions of mechanical formation damage and condensate banking to the well productivity impairment. Well models to predict the incremental production rate that can be expected after the remediation of the formation damage can be built by means of well test analysis and vertical flow profile calculations. In these models the effect of multiphase flow on the productivity of the wells is usually considered by means of the steady-state two-phase pseudopressure. Jones et al.[5] showed that for two-phase flow reservoir conditions, with the bottomhole flowing pressure below the dewpoint pressure of the original reservoir fluid composition, reliable estimates of permeability-thickness and reservoir pressure can be determined by pressure transient analysis using the Al-Hussainy et al's single phase gas pseudopressure[6] or Fussell's two phase pseudopressure.[7] The mechanical skin factor, however, can be approximated by well test analysis methods using the two-phase pseudopressure if the saturation distribution around the producer is adequately represented by the steady state theory. The steady state theory holds for the analysis of pressure data during transient flow or if most of the drainage area is above the dewpoint pressure in boundary dominated flow. When the reservoir pressure is close to or below the saturation pressure, well test analysis by Fussell's two-phase pseudopressure will fail to predict both flow capacity and skin. This is mainly due to the presence of a growing intermediate oil region and the resulting change in flowing composition. Fevang and Whitson3 proposed a modification to the pesudopressure calculation for depletion cases in which three regions exist around the well. As Xu and Lee 8 and Fevang and Whitson3 have reported, pressure transient analysis and well deliverability calculations by the Fevang and Whitson two-phase pseudopressure perform acceptably for depleting wells when the effects of capillary number on the relative permeability functions and the effective inertial resistance are negligible. As it will be shown later, neglecting capillary number and inertial effects can be a drastic assumption.

Abstract Production from gas-condensate reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of condensate near the wells causing a large decrease in both the gas and condensate relative permeability. Several methods such as hydraulic fracturing and solvents have been proposed to restore production rates but all of these methods have limitations or they are only effective for short periods of time. We have evaluated new surfactants using a methanol-water mixture as the solvent to treat cores under reservoir conditions. The surfactants have been tested under reservoir conditions using a variety of cores and found to be promising since they significantly increased the steady state relative permeability. Experiments were performed to evaluate the effectiveness of these surfactants at high temperature and high gas flow rates over a range of capillary numbers on the order of those near production wells. The productivity index for sandstone cores was improved by a factor of 2 to 3 for temperatures over the temperature range of 145 to 275 °F for the Novec FC 4430 polymeric surfactant in the methanol-water mixture. These treatments have the potential to greatly increase production at low cost since only the near well region of the reservoir blocked by the condensate needs to be treated. Introduction Gas-condensate reservoirs show a decline in productivity when the bottom hole flowing pressure drops below the dewpoint pressure of the fluid. Liquid condensate builds up near the well restricting the flow of gas. Capillary forces trap some of the condensate phase in the pores, which causes a reduction in the relative permeability of both the gas and condensate. The degree of condensate blocking depends indirectly on a combination of factors including fluid properties, formation characteristics, flow rate and pressure. A well-established example of condensate blocking and a reduction in productivity of more than a factor of two occurred in the Arun field.[1,2] When the pressure near the production wells falls below the dew point pressure, condensate blockage occurs near the production wells even before the average reservoir pressure drops below the dewpoint pressure of the fluid. Even for lean gas (1% liquid dropout), significant liquid saturations can build up near the wells. Liquid saturations near the wells can reach 50 to 60% under pseudo steady-state flow of gas and condensate.[3–6] Productivity reductions of 40–80% have been reported for some fields.[5] Reductions in relative permeability of greater than 95% in laboratory cores at low capillary number have been reported for both low and high permeability rocks.[7–10] Significant reduction in productivity index has also been reported.[11–13] Since the reduction in well productivity is primarily associated with the reduction in gas relative permeability, a great deal of effort has gone into measuring and modeling the relative permeability of gas condensate fluids. Several recent studies have been made using the pseudo pressure method for measuring relative permeability.[5–9,12–16] In this method, a gas mixture above its dew point pressure is flashed into the core at a reservoir pressure less than the dew point pressure and flowed until steady state is reached. This process is similar to what happens around the wells, is easy to control with the backpressure on the core, and is very efficient since saturations do not have to be measured. A model for predicting gas relative permeability as a function of trapping number (a generalization of the capillary and Bond numbers) was developed by Pope et al. [17] This model includes the dependence of gas relative permeability on interfacial tension, pressure gradient and buoyancy forces. In general, regions of high trapping numbers such as high permeability layers with high flow rates show lower condensate saturations and thus higher gas and condensate relative permeabilities. Non-Darcy flow can be significant in high rate gas wells. Narayanaswamy et al. [2] showed that reservoir heterogeneity plays an important role in determining the effective ß (non-Darcy flow coefficient) for gas inflow into high rate gas wells. The additional pressure drop caused by non-Darcy flow is closely coupled with the pressure profile near the well and thus the phase behavior.

Abstract Modern computing power has enabled very high accuracy and efficiency in complex calculations. Thus, it follows that reservoir engineering formulations need not be approximate solutions, as was sometimes historically the case. Being one of the most widely used techniques in reservoir engineering, the material balance equation (MBE) for gas is an excellent example of this. The MBE is used not only for estimating the original gas-in-place (OGIP), but also for calculating the decline in average reservoir pressure with depletion. In the majority of cases, the conventional p/Z formulation of the gas material balance is satisfactory. However, certain circumstances, which are sometimes unpredictable, demand formulations with greater accuracy. Although modifications to the standard approach have been presented, to the authors' knowledge, there is no published gas material balance formulation that is completely rigorous. This study presents a new, rigorous MBE for gas flow in the presence of a compressible formation and residual fluid saturation. Examples will be presented to highlight the capabilities of the new MBE. Introduction There has been a demand in the petroleum industry to plot the p/Z (or a similar plotting function) vs. cumulative gas production ( Gp ), as accurately as possible, so that the extrapolated line can point to the correct amount of OGIP. The primary value of this approach is to calculate the average reservoir pressures from the MBE. This has been one of the most powerful tools in reservoir engineering. Conventional MBE[1] for gas flow from a "volumetric" reservoir assumes the available pore volume to gas is constant by disregarding the effect of formation compressibility and the expansion of residual fluid during the productive life of the reservoir. Such assumptions may not be acceptable where the rock compressibility is of the same order of magnitude as residual fluid or gas. Ramagost and Farshad[2] modified the classical material balance equation and proposed a new plotting function as [( p/Z ) (1- ce ?p )] vs. Gp, based on an improved version of the conventional MBE. On a number of occasions with certain combinations of compressibility and saturation values, it has been observed that the Ramagost and Farshad MBE should have been more accurate in predicting the average reservoir pressure. We have examined how this MBE was derived. As will be shown later, the contributions of the shrinkage of the pore volume and of the expansion of residual fluid saturation were approximated in this approach. With the advent of computer power now-a-days, the accuracies of reservoir engineering calculations are warranted. The material balance equation (MBE) for gas flow has been used not only for estimating the OGIP, but also for estimating the average reservoir pressure. In addition, accuracies of MBE have to keep pace with the results from sophisticated reservoir simulations (both analytical and numerical). The following are the major applications of an MBE: To estimate average pressure for a given cumulative gas production. To estimate the cumulative gas production for a given average reservoir pressure. To estimate the OGIP from a given history of static pressure vs. cumulative production. To calculate pseudo-time[3] when using analytical solutions developed for liquids for modeling gas reservoirs. This study presents a new, rigorous MBE for gas flow in a compressible formation with residual fluid saturation. A new dimensionless parameter in the MBE will be identified and explained how this can predict the behavior the MBE. Examples will be presented to highlight the capabilities of the new MBE. The principal assumptions remain identical to those of Ramagost and Farshad[2] as compressibilities of rock and residual fluid are constant. Presentation of New MBE In the following sub-sections, we present the new, rigorous MBE, its implications and an explanation of the methodology of calculating the average reservoir pressure from it.

Abstract Well production performance tests were performed for a low resistivity, electrically anisotropic, laminated shaly sand gas reservoir. This paper compares such production test results with reservoir well simulation predictions based on log data, which include multicomponent induction measurements of formation resistivity anisotropy. Previously accurate gas well production performance evaluation of low contrast, low resistivity laminated shaly gas sand zones often required the performance of a production well test. A reliable prediction of well production performance through reservoir simulation based on log data has been a challenge. Such a predictive ability is required for optimum completion and field development decisions. The reliability of these simulation predictions has been compromised by the petrophysical limitations of gas-in-place evaluations for thinly bedded, laminated reservoirs. This situation arises whenever traditional scalar saturation equations are applied to conventional resistivity instrumentation data. Traditional laminar shaly sand saturation equations are based on a horizontal parallel conductivity model dominated by the high shale conductivities in vertical wells. These equations typically result in significant underestimates and uncertainties in gas-in-place evaluation in laminated zones. Such equations must be fine-tuned from one well to the next. Formations containing laminated sand-shale sequences and laminated sands of different porosity and/or grain size exhibit macroscopic electrical anisotropy. This formation property provides us with additional information about laminated hydrocarbon-bearing sands. New multicomponent induction logging hardware makes it possible to directly measure the vertical, R v , and horizontal, R h , resistivities and the resulting resistivity anisotropy (in the so-called transversely anisotropic media) for vertical, deviated, and horizontal wells. The use of both vertical and horizontal resistivities in petrophysical evaluation provides improved reservoir characterization, leading to better prediction of well production performance using reservoir simulation techniques. A standard suite of logs, including multicomponent induction data, was recorded in a well interval with thick and laminated sands within a gas reservoir. Petrophysical analysis of these laminated zones utilizing resistivity anisotropy has resulted in an approximately 20% increase of estimated gas-in-place over estimation methodologies previously applied to similar gas reservoirs1. Production test flow rates were compared with reservoir simulation predictions. Two interpretation results were considered in generating the simulation model, one incorporating the resistivity anisotropy tensor estimated from multicomponent induction tool measurements, and the other where a conventional, single resistivity interpretation was used. The 3DEX resistivity anisotropy data interpretation has lead to a more accurate shaly sand reservoir characterization of hydrocarbon volume-in-place which, when used with standard reservoir simulation techniques, resulted in better production flow rate prediction results in comparison with actual production well test results. Introduction Can additional log data such as resistivity anisotropy improve well flow prediction in laminated sand-shale sequences? Conventional estimation of fluid saturation in laminated sequences may lead to underestimating hydrocarbon reserves. The presence of laminations with thickness below that of the instrument resolution can result in an observed macroscopic anisotropy as described in Figure 1. Even though the thin, individual sand and shale laminae may be isotropic, the layered sequence of sands and shales exhibit apparent electrical anisotropy at the scale of the logging instrument resolution. Measuring the resistivity anisotropy and incorporating it in a petrophysical evaluation provides improved evaluation of thinly bedded reservoirs, leading to a considerable improvement in reservoir simulation predictions for well performance tests. This in turn provides support for the petrophysical evaluation results.