Original Gas In Place Research Articles

Unified Decline Type-Curve Analysis for Natural Gas Wells in Boundary-Dominated Flow

SummaryRate-time decline-curve analysis is the technique most extensively used by engineers in the evaluation of well performance, production forecasting, and prediction of original fluids in place. Results from this analysis have key implications for economic decisions surrounding asset acquisition and investment planning in hydrocarbon production. State-of-the-art natural gas decline-curve analysis heavily relies on the use of liquid (oil) type curves combined with the concepts of pseudopressure and pseudotime and/or empirical curve fitting of rate-time production data using the Arps hyperbolic decline model. In this study, we present the analytical decline equation that models production from gas wells producing at constant pressure under boundary-dominated flow (BDF) which neither employs empirical concepts from Arps decline models nor necessitates explicit calculations of pseudofunctions. New-generation analytical decline equations for BDF are presented for gas wells producing at (1) full production potential under true wide-open decline and (2) partial production potential under less than wide-open decline. The proposed analytical model enables the generation of type-curves for the analysis of natural gas reservoirs producing at constant pressure and under BDF for both full and partial production potential. A universal, single-line gas type curve is shown to be straightforwardly derived for any gas well producing at its full potential under radial BDF. The resulting type curves can be used to forecast boundary-dominated performance and predict original gas in place without (1) iterative procedures, (2) prior knowledge of reservoir storage properties or geological data, and (3) pseudopressure or pseudotime transformations of production data obtained in the field.

Global Unconventional Gas Resource Assessment

Summary Most estimates of the resource endowment [original gas in place (OGIP)] reported for world unconventional gas start with Rogner's top-down study (Rogner 1997). That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The data from these new reservoirs add substantially to our understanding of the unconventional resource base. Furthermore, the uncertainty of Rogner's assessment was not quantified. Thus, considering the uncertainty, a new assessment of original unconventional gas in place worldwide is needed. The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight-sand, and shale reservoirs worldwide. To accomplish this objective, we reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight-sands gas, and shale gas] and the conventional hydrocarbon (coal, conventional gas, and oil) resource endowments for North America. Then, we used this relationship to extrapolate original unconventional gas in place worldwide. Our assessment of the world resource endowment established an unconventional OGIP of 83,400 Tcf (P10) to 184,200 Tcf (P90), which is 2.6 to 5.7 times greater than Rogner's estimate of 32,600 Tcf. Our regional assessments of unconventional OGIP should help industry better target its efforts to rapidly accelerate the development of unconventional gas resources worldwide. The methodology used to assess the distribution of each type of unconventional OGIP may be used to estimate unconventional gas resources at the country or basin level, given knowledge of the coal in place and technically recoverable resources of conventional hydrocarbons.

New Estimation Technique Shifts Assessment of Global Unconventional Gas Resources

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 148365, ’Global Unconventional Gas Resource Assessment,’ by Z. Dong, S.A. Holditch, SPE, D.A. McVay, SPE, and W.B. Ayers, SPE, Texas A&M University, prepared for the 2011 SPE Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. As the world reserves of liquid hydrocarbons from conventional reservoirs peak and begin to decline, natural gas will play an increasingly important energy supply role. Most estimates of the original gas in place (OGIP) reported for world unconventional gas start with Hans-Holger Rogner’s 1997 top-down study. That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight sand, and shale reservoirs worldwide. Introduction To accomplish this objective, the authors reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight sands gas, and shale gas] and the conventional hydro-carbon (coal, conventional gas, and oil) resource endowments for North America. Then, they used this relationship to extrapolate original unconventional gas in place worldwide. For the assessments, P10, P50, and P90 are the values for which the probability is 10, 50, and 90%, respectively, that the value will be exceeded. This work established an unconventional OGIP of 83,400 Tcf (P90)–184,200 Tcf (P10), which is 2.6–5.7 times greater than Rogner’s estimate of approximately 32,600 Tcf. Global Unconventional Gas Base. According to Rogner’s estimates, world-wide original in-place resources were approximately 9,000 Tcf of CBM, 16,000 Tcf of shale gas, and 7,400 Tcf of tight sands gas. Rogner’s 1997 global estimate is most likely quite conservative, given the recent discovery of significant shale gas around the world. Resource Triangle. J.A. Masters suggested in a 1979 paper that hydrocarbon resource types can be assigned to various resource classes in a triangular distribution and that their positions in the triangle reflect their abundance, their reservoir quality, and the technology required for recovery (Fig. 1). As one goes lower on the gas resource triangle, the reservoirs are lower grade, which usually means the reservoir permeability is decreasing. These low- permeability reservoirs are much larger than the higher-quality reservoirs.

A density-diffusivity approach for the unsteady state analysis of natural gas reservoirs

The traditional approach employed in the analytical analysis of unsteady state responses for natural gas reservoirs is firmly based on recasting the non-linear pressure diffusivity equation in terms of pseudo variables or pseudofunctions—namely, pseudo-pressure and pseudotime—able to render the equation amenable to analytical treatment. Because the pseudofunction-based approach succeeds in linearizing the diffusivity equation and generating the required benchmark analytical solutions, the implementation of pseudo-variables is understood to be essential to unsteady state analysis of natural gas reservoirs. In this study, the authors propose an approach for the analytical solution of unsteady flow in natural gas reservoirs based on the use of the density-diffusivity equation. To demonstrate its validity and range of application, the authors discuss analytical arguments and perform numerical simulations to corroborate its performance for some of the most widely used inner boundary conditions (BCs): constant pressure and constant rate production. By implementing the concept of depletion-driven dimensionless parameters, the proposed density-diffusivity approximation is able to successfully describe reservoir unsteady behavior while keeping all variables involved in the analysis firmly grounded on physical intuition. In addition, it is shown that the proposed approach also provides a new avenue for the interpretation of liquid type-curves in gas analysis and the iteration-free estimation of original gas in place based on the analysis of boundary-dominated production data.

Natural-Gas Potential in the St. Lawrence Lowlands of Quebec:A Case Study

Summary Since the announcement made in April 2008 concerning the shale-gas potential of the southern Québec lowlands, 30 new wells have been drilled in the area. The calcareous and organic-rich Middle Ordovician Utica shale is the main target of this recent exploration effort. Current knowledge of the area's geology has led operators to subdivide the shale-gas potential into different play types. To date, most operations have been performed in approximately one-third of the shale basin in the medium-to-deep thermogenic shale-gas play (1000 to 2000 m), located in the central part of the Saint Lawrence lowlands. With original-gas-in-place (OGIP) estimates ranging from 120 to 160 Bcf per section, the deep play is considered to be promising. Current efforts focus on determining the highest gas-prone unit within the Utica. The remaining two-thirds of the shale basin has not been largely tested yet, but the potential remains promising. On the basis of exploration work carried out over the past 5 years in southern Québec, four other play types have been described: (1) shallow-to-medium-depth thermogenic shale gas, (2) overthrusted shale gas, (3) biogenic shale gas, and (4) Intra-Appalachians subbasin shale gas. They are less explored than the deep-shale play, but also present interesting potential. This paper describes the previously mentioned plays using basin geology, shale mineralogy, organic-matter type, gas geochemistry, structural style, and infrastructure access. The characteristics of the previously described plays are reviewed from geological, geochemical, structural, and production perspectives. Results of evaluations using the concept of flow units, and volumes of OGIP calculated by various organizations, are compared with a recent evaluation using the petroleum resources management system (PRMS). It is concluded that there is promising hydrocarbon potential in the Saint Lawrence lowlands of Québec that continues to stimulate operators to pursue the exploration and development of these plays.

A New Model for Modern Production-Decline Analysis of Gas/Condensate Reservoirs

Summary Modern production-decline analysis is a robust technique for analysis of production data from a well under variable operating conditions. It uses production rates and flowing pressures to provide reliable estimates of recoverable reserves and fluid in place. The mathematics behind this technique is similar to that of pressure-transient theory; however, the focus is different. It deals with long-term variable production data instead of short-term constant-rate transient data. Using modern decline analysis for two-phase-flow conditions (e.g., gas/condensate reservoirs) is under question because of the single-phase-flow assumption in the development of a "material-balance time" function. This is a time function that converts any decline (e.g., exponential decline) to harmonic decline to account for variable operating conditions. The purpose of this work is to develop a model to use the concepts of modern techniques for analyzing production data of single-porosity gas/condensate reservoirs. For this purpose, the governing flow equation is linearized, using appropriately defined pseudopressure and pseudotime functions. Then, the solution is obtained for constant-well-rate condition. This is followed by employing the superposition theorem to account for variable well pressure/rate conditions, resulting in definition of two-phase material-balance pseudotime. The solution developed here is coupled with an appropriate material-balance equation and used to estimate the average reservoir pressure and original gas in place from analyzing production data. The dependency of relative permeability on capillary number and non-Darcy flow is included in the formulation. Verification of the proposed method is obtained with the analysis of synthetic production data using a series of fine-grid compositional numerical simulations over a typical range of gas/condensate-reservoir parameters.

Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modelling the Tommy Lakes Gas Field

Summary The Tommy Lakes field is located in northeastern British Columbia, Canada, and is one of the largest Middle Triassic gas pools within the western Canada sedimentary basin (WCSB). The major gas-production formation (Halfway/Doig reservoirs) at the Tommy Lakes field corresponds to shoreface sands with permeabilities ranging between 0.1 and 3 md, and porosities of 3 to12%. For the purpose of production optimization and field development, a full-field reservoir model was developed with the integration of advanced reservoir characterization, hydraulic-fracture modelling, and history-matching techniques. This study presents an integrated workflow for modelling the low-permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed on the basis of concepts emanating from an outcrop analogue analyzed with terrestrial light detection and ranging (LiDAR) technology and 60 wells that represent the fundamental rock characteristics, structure, facies? proportions, and petrophysical properties of the Doig anomalously thick sandstone bodies (ATSBs). Structural tops were interpreted from well logs and permeability/porosity relationships established from quantitative log analysis and core/log calibration. Facies were identified in cored intervals and were further grouped into four lithofacies. An artificial neural network (ANN) was used for training the logs of key wells [gamma ray (GR), neutron porosity (NPHI), and bulk density (RHOB)] and populating the facies distribution of uncored wells. Facies-based log-derived porosity, permeability, shale volume, and water saturation were assigned to gridblocks using sequential Gaussian simulation (SGS). Finally, the Monte Carlo simulation approach was used to rank the key variables affecting original gas in place (OGIP) in the uncertainty and optimization process. Flow-based techniques were used for upscaling reservoir properties into the coarse simulation grid. The full-field simulation model was calibrated with buildup data and hydraulic-fracture modelling of single wells. Production of the Doig channel from commingled wells was allocated systematically in order to achieve a good match of the gas-production history and bottomhole pressures. Sensitivity analysis of fracture half-length and its impact on ultimate gas recovery was investigated. This concluded with an integrated development strategy. It is concluded that integration of multiple domains leads to a valid full-field reservoir model, which is critical in developing an integrated strategy, predicting reservoir performance, and optimizing gas production.

A critical evaluation of unconventional gas recovery from the marcellus shale, northeastern United States

The Marcellus tight gas shale represents a significant resource within the northeastern United States. It is both a large reserve, with an estimated 30 to 300 TCF of recoverable gas, and is close to some of the largest prospective markets in the country. However, production is fraught with technological obstacles, the most significant of which include prospecting, access by drilling, stimulation, and recovery. Prospecting is difficult because viability of the reservoir relies both on the original gas in place and in the ability to access that gas through pre-existing fractures that may be developed through stimulation. Drilling is a challenge since drilling costs typically comprise 50% of the cost of the wells and access to the reservoir is improved with horizontal drilling which may access a longer productive zone within the reservoir than cheaper vertical wells. Finally, stimulation methods are necessary to improve gas yields and to reduce the environmental impacts of both consumptive water use and the subsequent problems of safe disposal of fracwater waste. We discuss the challenges involved in the economic recovery of gas from tight gas shales in general and the Marcellus in particular.

Advanced Gas Material Balance in Simplified Format

Summary Material balance has long been used in reservoir engineering practice as a simple yet powerful tool to determine the original gas in place (G). The conventional format of the gas material balance equation is the simple straight line plot of p/Z vs. cumulative gas production (Gp), which can be extrapolated to zero p/Z to obtain G. The graphical simplicity of this method makes it popular. The method was developed for a "volumetric" gas reservoir. It assumes a constant pore volume (PV) of gas and accounts for the energy of gas expansion, but it ignores other sources of energy, such as the effects of formation compressibility, residual fluids expansion and aquifer support. It also does not include other sources of gas storage, such as connected reservoirs or adsorption in coal/shale. In the past, researchers have introduced modified gas material balance equations to account for these other sources of energy. However, the simplicity of the p/Z straight line is lost in the resulting complexity of these equations. In this paper, a new format of the gas material balance equation is presented, which recaptures the simplicity of the straight line while accounting for all the drive mechanisms. It uses a p/Z** instead of p/Z. The effect of each of the previously mentioned drive mechanisms appears as an effective compressibility term in the new gas material balance equation. Also, the physical meaning of the effective compressibilities are explained and compared with the concept of drive indices. Furthermore, the gas material balance is used to derive a generalized rigorous total compressibility in the presence of all the previously mentioned drive mechanisms, which is important in calculating the pseudotime used in rate transient analysis of production data.

Global Unconventional Gas - It Is There, But Is It Profitable?

Management Gas reservoirs are often classified as conventional or unconventional. Conventional gas reservoirs are characterized by high permeability with the gas stored in sand or carbonate formations in pore spaces that are interconnected. A gas resource is generally considered conventional if it does not require a large stimulation treatment to be able to produce oil and gas at economic flow rates. An unconventional gas reservoir can be defined as a natural-gas reservoir that cannot be produced at economic flow rates or in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or multilateral wellbores (Holditch, 2006). The three most common types of unconventional gas resources are tight sands, coalbed methane, and gas shales. Unconventional gas reservoirs are characterized by low permeability, in the microdarcy range (Fig. 1) or less. As the permeability deceases, the economic risk of developing the resource increases, and the investment required also increases because more wells have to be drilled to produce the reservoir, as each well recovers less gas per well than one can recover per well from a conventional reservoir. The US Department of Energy’s (DOE’s) Energy Information Administration (EIA) defines the total natural-gas resource base as all of the gas that has ever been trapped inside the Earth, including the volumes that have already been produced. The part of the total natural-gas resource base that interests investors most, however, is the remaining natural gas waiting to be extracted. Research indicates the existence of large, unconventional gas reservoirs located throughout the world. Rogner (1997) estimated that there are 9,000 Tcf of original gas in place (OGIP) reserves in coalbed methane, 16,000 Tcf of OGIP in shale gas, and 7,400 Tcf of OGIP in tight gas sands around the world (Table 1). Since Rogner published his paper, the oil and gas industry has discovered enormous volumes of natural gas in unconventional gas reservoirs in North American and in several other basins around the world. It is believed that the OGIP estimates in Table 1 are very conservative. The industry will be updating the values in Table 1 and it is expected that the values of OGIP will increase substantially. With declining conventional gas reserves in the United States, unconventional gas reservoirs are emerging as critical energy sources to meet the increasing demand for energy. The US DOE April 2009 report, Modern Shale Gas Development in the United States: A Primer, stated that over the last decade, production from unconventional resources in the US has increased almost 65%, from 5.4 Tcf/yr in 1998 to 8.9 Tcf/yr in 2007. This increase in production indicates that approximately 46% of today’s US total gas production comes from unconventional resources (Navigant 2008).

Horizontal-Well Completions for Developing Low-Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment - A Case Study

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116542, "Successful Application of Horizontal-Well Com pletions for Development of Low-Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment - A Case Study," by Chatib Hazman, Harry Alam, Shinta Damayanti, Andre Wijanarko, Zainal Arifin, R. Rahardjo, Heriadi Buhron, and Robert Nikijuluw, Virginia Indonesia Company; Gary J. Sable, ENI; and Ram K. Narayanan, Donn Schmohr, and Martin Rylance, BP plc, prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed. Virginia Indonesia Company operates the Sanga-Sanga production-sharing contract (PSC) onshore at the Mahakam delta, East Kalimantan, Indonesia. The PSC has produced more than 70% of its estimated original gas in place. The fields are relatively mature, with the remaining gas resources in either pressure-depleted reservoirs or in low-permeability reservoirs for which conventional techniques have not been effective. A pilot development tested the use of horizontal completions. Introduction The Sanga-Sanga PSC fields are in the Kutai basin. Hydrocarbon accumulations typically are within the Mid-Miocene upper-delta and delta-plain sandstone-reservoir depositions. Exploration of this area began in 1968. The Nilam field has more than 16,000 ft of stacked lenticular gas-bearing sands and more than 1,300 individual gas reservoirs. More than 250 production wells have been drilled in the field. The condensate/gas ratio ranges from 5 to 30 bbl/MMscf. Liquid production presents two problems in the low-permeability sands: liquid loading and condensate banking. Conventional vertical wells are very susceptible to liquid-loading problems because the rates typically are below critical rates required to lift the fluid out of the well. Condensate banking exacerbates the problem by increasing near-wellbore oil saturation and reducing the relative permeability to gas. Horizontal wells are less affected by condensate-banking effects because of the larger flow area and, therefore, are able to handle higher flow rates. The strategy was to drill and complete horizontal wells that would deliver sufficient rates for a long period, recovering the same reserves as and replacing two or three conventional vertical wells. The well-candidate selection approach was based on a combination of the geological, reservoir-evaluation, and drilling considerations to mitigate risk, maximize recovery, and minimize costs. Team Approach A horizontal-well team was established comprising geologists and reservoir, petroleum, and drilling engineers. The team established a three-step process: Successfully drill, prove productivity, and optimize (cost and productivity). This crossdiscipline team selects candidates, then models and plans each well, obtains approval, and executes the drilling and completion. After each well was drilled and put on production, the horizontal-well team performed a post-well review, identifying lessons learned for use in designing the next well. This method provided continuity in the program and allowed a more rapid climb up the learning curve.

Case Study: Production Data and Pressure Transient Analysis of Horseshoe Canyon CBM Wells

Abstract The Horseshoe Canyon (HSC) CBM play of the Western Canadian Sedimentary Basin is unique to low-rank coal reservoirs because of lack of water production; the production characteristics are qualitatively similar to conventional low-pressure dry gas reservoirs. However, the complex geological history of the coals and non-coal interbeds has imparted strong vertical and lateral heterogeneities that make the play difficult to characterize using conventional methods. Recently, advances in production data analysis (PDA) methodologies have been made for CBM wells; techniques developed for conventional oil and gas reservoirs have been adapted by incorporating some CBM reservoir properties. For example, the popular flowing material balance (FMB) technique, as well as production type-curve and pressure transient analysis (PTA) have been modified to include relatively simple CBM reservoir behaviour (ex. equilibrium desorption). These methods, however, are primarily restricted to the analysis of single-layer reservoirs; significant errors in estimates of original-gas-in-place (OGIP) and other reservoir properties may occur if strong contrasts exist from layer-to-layer. In this work, multi-layer analysis tools are discussed, including analytical simulators that are used to history-match layer-allocated rates and pressures, and layer-specific FMB, which is used as a PDA method for individual layers. The applicability of advanced PDA methods to the quantitative assessment of HSC reserves was investigated. Single-layer and multi-layer analysis tools were first tested against simulated data. Next, single-layer-equivalent analysis was performed on >40 real wells using type-curve, FMB, and analytical simulation. Finally, a more rigorous multi-layer analysis was performed on a subset of wells where spinner surveys and individual-seam pressure buildup data were available. Analysis of these wells included PTA of the individual seams, individual seam material balance, and multi-layer analytical model history-matching of total commingled flow rates, individual coal zone rates estimated from spinner surveys and shut-in pressures. The single-layer- equivalent analysis appears to yield conservative estimates of OGIP compared to the more rigorous multi-layer analysis in the cases analyzed. Future work will include continued comparisons of multi-layer vs. single-layer PDA, investigation of additional constraints on input reservoir properties used in multi-layer history-matching process, and time-lapse PTA work to quantify changes in layer permeability and skin during depletion.

State-of-the-Art Tight Gas Sands Characterization and Production Technology

Abstract As part of the activities of the ConocoPhillips-NSERC-AERI Chair in Tight Gas Engineering established in the Chemical and Petroleum Engineering Department at the University of Calgary, a comprehensive literature review has been conducted that has led to an understanding of the current status of the study of tight gas sand formations. This paper presents the results of that work, concentrating initially on Canadian and U.S. tight gas sands. The literature survey discussed in this paper is the first part of the mission-oriented research on tight gas reservoirs conducted at the University of Calgary. The planned research looks at refining the resource base and recoveries from tight gas formations in Canada. Evaluating the current status of geologic models, reservoir characterization, recovery and production technologies currently available for these types of formations is the first step in the effort to reach the final goal: finding the economic means of producing as much of this gas as possible. It is expected that the research results will prove to be of value in other parts of the world and will be exportable, creating business opportunities for Canadian companies. The program will also result in a supply of highly qualified professionals having significant knowledge of tight gas formations. Introduction The complete reference list and interpretation of tight gas sands are presented by Aguilera and Harding(1). Tight gas sands are part of what is usually known as unconventional gas, which also includes coalbed methane, shale gas and natural gas hydrates. Although tight gas production is not reported separately in Canada, interest in this resource is growing significantly. Tight gas sands have been defined in different ways by different organizations and a unique definition has proven elusive. The original definition dates back to the U.S. Gas Policy Act of 1978 that required in situ gas permeability to be equal to or less than 0.1 mD for the reservoir to qualify as a tight gas formation. At present, this is probably the most commonly accepted definition. The National Energy Board (NEB) of Canada placed tight original gas-in-place at between 89 and 1,500 Tcf in 1999(2). The Canadian Association of Petroleum Producers (CAPP) indicates that, more recently, the National Energy Board estimated that Canada has 300 Tcf of tight gas-in-place(3). Although the figures vary significantly among different estimators, the pervasive opinion among experts is that there are significant volumes of gas-in-place in Canadian tight gas sands. The estimated volumes of unconventional gas throughout the world are gigantic, as shown in a study presented by Rogner(4). He estimated tight original gas-in-place (OGIP) at 7,500 Tcf for the entire world. Our preliminary estimates suggest that this figure is conservative. For other unconventional gas sources, the volumes are even higher. The above tight gas volumes are in, at most, 271 of the 937 recognized petroleum provinces in the world. An evaluation of the resources from the remaining provinces would lead to even higher estimates, as has occurred with more conventional hydrocarbon reservoirs(5).

Effect of Fracture Compressibility on Gas-in-Place Calculations of Stress-Sensitive Naturally Fractured Reservoirs

Summary A tank material-balance equation for gas reservoirs has been written, taking into account the effective compressibility of matrix and fractures. The method has direct application to stress-sensitive naturally fractured reservoirs (NFRs). Under some conditions, ignoring the effect of fracture compressibility (Cf) can lead to overestimating the volume of original gas in place with a crossplot of p/z vs. cumulative gas production (Gp). The equation presented in this paper has been developed to overcome that weakness. The use of the tank material balance is illustrated with an example. It is concluded that fracture compressibility can play an important role in the calculation of gas in place in stress-sensitive NFRs. The subject matter is significant because, historically, formation and water compressibilities have been neglected when carrying out material-balance calculations for conventional gas reservoirs. This assumes that these compressibilities are negligible compared to that of gas. The assumption implies that the reservoir strata are static. When water influx is ignored, the assumption leads to a straight line in a crossplot of p/z vs. Gp. However, this study shows that in those instances in which fracture compressibility is large, such assumptions can lead to significant error.

The Importance of Initial Reservoir Pressure for Tight Gas Completions and Long-Term Production Forecasting

Abstract Flow and buildup testing of gas wells in Alberta is common practice for the determination of reservoir pressure, permeability and wellbore skin. Post-frac welltesting is still regarded as the preferred welltesting method, due in part to current government regulations for initial testing requirements. With the maturing of the Western Canadian Sedimentary Basin (WCSB) in recent years, the development of unconventional gas reservoirs has significantly increased. Deep tight gas reservoirs have become an important part of unconventional gas resources and this paper will address several issues and pitfalls related to the welltesting of tight gas. Initial reservoir pressure is probably one of the most important ‘data points’ for reservoir engineering and completion design and yet one of the most abused and assumed parameters. Field examples will highlight major errors that are likely to occur when post-frac flow and buildup tests are analyzed for tight gas reservoirs without precise knowledge of the initial reservoir pressure. This paper will demonstrate that errors of reservoir pressure as small as 2% can lead to significant overestimates of the well 's recoverable reserves. Introduction The strong commodity prices in the energy sector experienced in recent years have resulted in an increased activity level for the development of unconventional tight gas reservoirs. Natural gas price is the major factor that will determine the economic viability of tight gas reservoirs. However, there are additional factors that should be taken into consideration, such as original-gas-in-place, completion efficiency, well spacing and the ultimate recoverable reserves. Unlike conventional gas reservoirs where proven reservoir engineering techniques are easily applied, the predictability of deep tight gas reservoirs is much more difficult to achieve. Too often the post-frac welltest results from wells completed in tight gas reservoirs are used to establish initial pressure, completion effectiveness and reservoir permeability for production forecasting for economic decisions. The flow behaviour of hydraulically fractured tight gas reservoirs is very complex and significant errors in the determination of matrix permeability and fracture parameters often occur. These errors can have a significant impact on predicting gas production and total cumulative gas recovery. Discussion With the maturing of the WCSB and high natural gas prices, the activity levels in the oil and gas industry have increased to record levels. So has an increased number of tight gas well completions. Generally speaking, performance evaluation of tight gas wells reveals a trend where the production performance of the wells is much less than what was initially predicted. These errors are considered the result of overestimating reservoir parameters such as the reservoir flow capacity (kh). Short references will be made to some of the factors determining the success of developing a tight gas resource:Original-gas-in-place (OGIP) is usually determined by the volumetric method and requires knowledge of reservoir pressure, mapping and petrophysical parameters. One equation used for estimating OGIP is:Equation (1) (Available In Full Paper)Hydraulic fracturing is a necessary step in the completion process in tight gas reservoirs in order to achieve commercial production.

Static and Dynamic Uncertainty Management for Probabilistic Production Forecast in Chuchupa Field, Colombia

SummaryStructural, stratigraphic, and petrophysical uncertainties result in a wide range of geologic interpretations. For fields with a long production and pressure history, 3D dynamic simulations have been very useful in providing feedback to geologic modelers, which results in improved static models. For this study, we developed an integrated static and dynamic workflow to create a range of probabilistic simulation models to forecast dry-gas production under several production scenarios in the Chuchupa field.We selected eight geologic interpretations, representing the range of original gas in place (OGIP) and reservoir geometries determined in the static modeling, to perform dynamic history matches. The OGIP range of the models with very good history matches corresponds closely to the P10 to P90 OGIP range calculated from static modeling.In addition, we calibrated the various models with historical bottomhole and tubinghead flowing pressures and coupled the reservoir model with a network consisting of surface lines and equipment, pipelines from two platforms to the onshore sale-point station, and multistage compression to 1,215 psia. The set of probabilistic models is currently used to evaluate various production and market scenarios.

A Volcanic Reservoir: Integrated Facies Distribution Modeling and History Matching of a Complex Pressure System

Summary A Tcf-class gas field has been producing over several decades in Japan. The reservoir body comprises stacked rhyolite lava domes erupted in a submarine environment. A porous network developed in each dome and rapid chilling on contact with seawater caused hyaloclastite to be deposited over it. Although hyaloclastite is also porous in this field, its permeability has been reduced dramatically by the presence of clay minerals. Impermeable basaltic sheets and mudstone seams are also present. Each facies plays a specific role in the pressure system. Stratigraphic correlation originally identified multiple reservoirs. Gas has been produced almost exclusively from the largest one. However, following 10 to 20 years of production, the pressures within unexploited reservoirs were noticed to have declined at a variety of rates. Unusual localized behavior has also been observed. Because seismic data were not proved particularly informative, we decided to remodel the entire system by specifically using pressure data. We employed a combination of multipoint geostatistics and probability perturbation theories. This approach successfully captured the curved facies boundaries within stacked lava domes while accounting for pressure data by means of history matching to address nonstationarity in the real field. Building a suitable training image is commonly a difficult aspect of multipoint methods and poses particular problems for volcanic reservoirs. It was accomplished here by iteratively adjusting the prototype until satisfactory history matching was achieved with a reasonable number of perturbations. Ambiguous reservoir boundaries were represented stochastically by populating a predetermined model space with pay and nonpay pixels. The modeling results closely simulate measured pressure histories and appear realistic in terms of both facies distributions and reservoir boundaries. They suggest that uneven pressure declines between different units are caused by the tortuous flow channels that connect them. The results also account for the unusual smaller-scale pressure performances observed. The final training image obtained here indicates more intensive spatial variations in facies than previously appreciated. Original gas in place (OGIP) estimates made with 20 equiprobable realizations are scattered within ±15% of the mean value. Estimates of incremental recovery made by drilling a step-out well reveal greater variation than those made by installing a booster compressor, which quantifies a higher associated geological risk.

Gas Diagnostics: To Drill or Not to Drill?

Abstract A very important but often difficult question to answer when dealing with gas reservoirs is: to drill or not to drill? Why are some gas pools only drilled at two wells per section and some drilled up to 16 wells per section? How do you decide whether downspacing will be beneficial? An accurate assessment of important factors such as capacity (kh), original gas-in-place (OGIP), and reservoir continuity is required. This paper describes a set of techniques that can be used to confidently assess kh, OGIP, and continuity in a gas reservoir. This information is then used to help determine if infill drilling has the potential to be beneficial. The following diagnostic techniques are simple to use and do not require a lot of time to perform. These techniques let the historical production/pressure data do the talking, so detailed geological modelling/mapping is not required. This fact, in combination with their effectiveness, makes them a must-have tool in any reservoir engineer's repertoire. The techniques include:Using the inflow equation coupled with simple gas material balance to determine the effectiveness of recent infill wells, along with the determination of kh and OGIP;Looking at initial productivities or initial measured pressure vs. on-production data for a group of wells in the same formation to determine continuity and heterogeneity; and,Calculation of the "depletion index," which is an innovative tool in which the level of depletion is quantified, and can then be used to compare to other pools. The techniques are described in detail and then applied in a case study where infill drilling was successful, and one in which it wasn't so successful, to illustrate how they work. Introduction Gas field development and optimal spacing depends upon resources in place (OGIP), the deliverability of wells (function of kh), the production profile, the reservoir continuity, and costs. Due to uncertainty in reservoir continuity, significant work has been done to optimize gas fields. Many of the previous works have used statistical techniques to identify infill potential. This paper shows a combination of analytical/statistical techniques that use an "average well" concept to determine infill drilling potential. A tie between physical parameters (such as permeability and apparent OGIP) and infill opportunities is developed. The method is especially powerful since it shows the connectivity and incremental recovery earlier than can be confidently extrapolated from decline analysis. This technique allows the operator to make development decisions about the field more rapidly. This analytical tool calculates the theoretical gas inflow performance through coupling of the pseudo steady-state (PSS) inflow and material balance(1) equations. The PSS inflow equation is only applicable after transient effects have subsided. The time to PSS flow can be determined with the following equation: Equation (Available In Full Paper) It is important to note that gas rates prior to the onset of PSS are transient and, thus, are higher than the rate that would be achieved in PSS flow when depletion is occurring.

Tight Gas Sands

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Tight gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs developed in the past are sandstone, but significant quantities of gas also are produced from low-permeability carbonates, shales, and coal seams. In this paper, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight-carbonate and gas-shale reservoirs. In general, a vertical well drilled and completed in a tight gas reservoir must be successfully stimulated to produce at commercial gas-flow rates and produce commercial gas volumes. Normally, a large hydraulic-fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells can be drilled, but these wells also need to be stimulated. To optimize development of a tight gas reservoir, a team of geoscientists and engineers must optimize the number and locations of wells to be drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher-permeability conventional reservoirs. On an individual-well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher-permeability conventional reservoir. As such, many more wells (closer well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place compared with a conventional reservoir. Definition of Tight Gas Reservoir In the 1970s, the U.S. government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many physical and economic factors. The physical factors are related by Darcy's law, as shown in the stabilized, radial-flow equation, Eq. 1, (Lee 1982).

The Importance of Comprehensive Gas Field Surveillance

Abstract Outline of Problem Gas field surveillance historically has not been given the same priority as oil field surveillance because of a couple of significant stumbling blocks: first, the apparent simplicity of gas reservoirs- at least upon initial examination; and, second, the historically low commodity prices of gas relative to oil. The presumption that gasfield surveillance was easily derived from the knowledge that, in most gas pools, single phase flow existed, leading to the assumption that "tank like" behaviour was occurring. However, on examination of hundreds of gas pools, my viewpoint on that matter has changed dramatically. Of course, today's commodity prices are also changing both the relative and absolute perceptions about the economic importance of gas. Initially, in the Western Canadian Sedimentary Basin (WCSB), industry encountered and dealt with very high quality gas resources, such as those found in Leduc reservoirs. These reservoirs had high permeability and were not compartmentalized; this naturally led to the "tank model" approach. These pools had behaviour as illustrated by Figure 1(a). In the last few years, we have moved from what I would term "Tier One" resources to lower quality ones, as shown in Figure 2. Indeed, a large portion of reservoirs do not exhibit that "tank like" behaviour shown in Figure 1(a); instead, there is often a fairly large pressure gradient across pools and non-tank like behaviour, such as that shown in Figure 1(b). This paper stresses the importance of comprehensive surveillance for those types of fields, using simple methods of production analysis and pressure diagnostic tools. There has been an explosion of research on using gas rate decline methods to characterize reservoirs with an effective permeability less than 0.1 mD (k < 0.1mD). However, the transient gas rate decline and practical analysis of such low permeability gas reservoirs are not the focus of this paper. This paper instead focuses on gas field surveillance for multi-well pools in which wells are in boundary dominated flow. The objectives of any gas surveillance program are relatively simple:What is the Original Gas in Place (OGIP)?;What is the current gas in place?;Where is the current gas in place located?;What is the permeability or capacity (kh) of the wells and pool?;What are the limiting considerations to gas recovery factor (low permeability, liquid lifting problems, low continuity, high back pressure, or water influx)?;What can be done to improve the rate of recovery and the recovery factor? and,Can this be done economically? In order to understand the above questions, we must relate the static model (geological/petrophysical) to the dynamic (production/ pressure data) one. Surveillance Methodology The following work flow has proven to be useful in determining the true potential of gas reservoirs:Examine the production profile of individual wells and the field. Examine the initial production rates (IP), interference effects, types of decline, and decline rates (production diagnostics);