Reservoir Engineering Techniques Research Articles

The Influence of Gas Lift on Oil Drainage Area in Reservoirs

Abstract Gas lift is a widely employed artificial lift method in the oil and gas industry, with the potential to significantly impact oil recovery from reservoirs. This study investigates the effect of gas lift on the oil drainage area within reservoirs, aiming to enhance our understanding of its role in reservoir management. Using advanced reservoir engineering and simulation techniques, the research explores the dynamics of gas lift and its influence on the accessibility of hydrocarbon resources. The study provides a comprehensive analysis of gas lift parameters, including gas injection rates, depths, and configurations, and their collective impact on the drainage area. It also considers the interplay between gas lift operations and reservoir characteristics such as permeability, porosity, and fluid properties. Findings from this study reveal that gas lift can effectively expand the drainage area by reducing bottomhole pressures and facilitating the movement of oil within the reservoir. This expansion enables the recovery of hydrocarbons from previously untapped regions, resulting in improved oil production. The research underscores the importance of optimizing gas lift design to maximize reservoir performance. Additionally, the study addresses operational challenges associated with gas lift, including gas allocation, injection optimization, and equipment reliability. It provides insights into the economic and operational considerations of gas lifts, offering valuable recommendations for reservoir management. The outcomes of this research contribute to a deeper understanding of how gas lift influences the oil drainage area in reservoirs, providing valuable insights for reservoir engineers, operators, and industry professionals involved in oil production. This knowledge supports informed decision-making to optimize oil recovery, reservoir performance, and the efficient use of gas lift technologies.

Research and Application for Alternate Production Technology of Dual-Branch Horizontal Wells in an Offshore Oilfield

Old-well sidetracking is a key method for controlling low-productivity wells in the Bohai oilfield. This study employs reservoir engineering and numerical simulation techniques to investigate the maximum drainage radius and natural coning control mechanism in heavy-oil reservoirs with bottom water. Based on these findings, an alternate production technology was developed for dual-branch horizontal wells. The technology creates a new branch through sidetracking, connecting and isolating the old and new wellbores using a combination of wall hangers and branch guides. Initially, the old wellbore with an ultra-high water cut is temporarily sealed. When the new branch reaches a high water-cut stage, production is switched back to the old wellbore. This technology was successfully applied to three wells in the Bohai oilfield, resulting in the new branch achieving expected production levels, while reopening the old wellbore increased daily oil output by 27 m3 and reduced water cut by 5.6%. Cumulative oil production from these wells reached 95,000 m3. This technology improves well-slot resource utilization, enhances recovery rates, and has significant potential for broader application.

Impact of well completion types on oil drainage area in reservoirs

Well completion design plays a crucial role in oil production and reservoir management. This study examines the influence of various well completion types on the oil drainage area within reservoirs, with the goal of enhancing our understanding of how completion methods affect hydrocarbon recovery. Using advanced reservoir engineering techniques and simulations, this research investigates the dynamic interaction between well completion and the accessibility of oil resources. The study provides a comprehensive analysis of different well completion types, including open-hole completions, cased-hole completions, and multilateral completions, and evaluates their collective impact on the drainage area. It also explores the interplay between well completion strategies and reservoir properties, such as permeability, lithology, and fluid characteristics. The findings of this study reveal that the choice of well completion type can significantly influence the drainage area by affecting the flow paths and reservoir contact. Different completion methods can extend or limit the reach of hydrocarbon recovery, impacting oil production rates. The research underscores the importance of optimizing well completion design to maximize reservoir performance. Furthermore, the study addresses operational considerations related to well completion, including equipment selection, production optimization, and workover requirements. It offers insights into the economic and operational implications of different well completion strategies, providing valuable guidance for reservoir management. The outcomes of this research contribute to a deeper understanding of how well completion types impact the oil drainage area in reservoirs. This knowledge is valuable for reservoir engineers, operators, and industry professionals involved in oil production, assisting them in making informed decisions to optimize oil recovery, reservoir performance, and well completion strategies.

Technology Focus: Reservoir Surveillance (September 2022)

When it comes to reservoir surveillance, subsurface professionals have a broad array of tools and techniques to understand what is happening in the reservoir. To ensure valuable information is gathered with surveillance, it’s important to first ask “what problem are we trying to solve?” Depending on the problem’s definition and scale, the appropriate surveillance technology will change significantly. Zooming far out, particularly if little data is available for a reservoir, we may be interested in tools and techniques to validate and refine the geological concept for a basin, along with the most likely deposition patterns for sediments. Zooming in to the level of interactions between wells, we need to use a different toolbox that often includes finer-resolution geoscience mapping and engineering methods such as analyzing production, pressure, and fluid-property trends from individual wells. But what’s really exciting is that many new approaches are being developed to understand reservoir behavior and well performance at incredibly high resolution—at the fracture scale or even the pore scale. In this feature, we will examine surveillance technologies that can be applied at the broad scale, midscale, and fine scale. The papers highlighted in this month’s feature apply forward stratigraphic modeling to improve geological models, classical reservoir engineering techniques to understand interwell connectivity in order to optimize waterflooding operations, and exciting new fiber-optic technology to characterize the performance of individual hydraulic fractures in unconventionals. I hope these articles help you to think about “framing” the problem you are trying to solve, like a photographer carefully selecting the right camera settings and lens for a specific shot, in order to select the right tools and methods to add value through surveillance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202319 - Utilizing Surface Microseismic Monitoring To Improve Understanding of Natural Fractures in Sichuan Shale Gas Play by Cui Jing, Sichuan Changning Natural Gas Development Company, et al. SPE 202837 - Modified Technique To Model Volatile Oil Reservoirs: Implications for Modern Software Programs by Mohamed Ibrahim, Shell Egypt, et al. SPE 201543 - Production Optimization Using a 24/7 Distributed Fiber-Optic DFO Sensing-Based Multiphase Inflow Profiling Capability by Teymur Sadigov, BP, et al.

Toolkit Approach Aids Design of CCS Projects in Depleted Offshore Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31651, “A Toolkit for Carbon Capture and Storage in an Offshore Depleted Gas Field,” by Raj Deo Tewari, SPE, Chee Phuat Tan, SPE, and Mohd Faizal Sedaralit, SPE, Petronas. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. Comprehensive screening for site selection has been carried out for suitable carbon dioxide (CO2) storage sites offshore Sarawak, Malaysia, using geographical, geological, geophysical, geomechanical, and reservoir engineering data and techniques for evaluating storage volume, container architecture, pressure, and temperature conditions. The site-specific input data are integrated into static and dynamic models for characterization and generation of performance scenarios of the site. Three-way coupled modeling helped to understand the likely state of injectants in the future and associated storage mechanisms. The work flow described in the complete paper may be adopted to evaluate other CO2 projects in both carbonate and clastic reservoirs for long-term storage of greenhouse gas (GHG) worldwide. Introduction Because fossil fuels are expected to remain a significant energy source until at least the middle of this century, techniques to capture and store produced CO2, combined with other efforts, could help stabilize GHG concentration in the atmosphere. The toolkit the authors present in the complete paper can help to design carbon capture and storage (CCS) projects for the oil and gas industry offshore. The authors aim to meet the following goals: - Provide process descriptions by which CCS can protect the environment - Describe steps required in planning and execution and post-operation - Protect human health and safety - Protect underground sources of drinking water and other natural resources - Comply with regulations for emissions reduction - Deploy technologies in an efficient and cost-effective manner The authors devote much of the complete paper to a discussion of factors to be considered in storage-site screening and selection, including the characteristics of different types of storage sites and their mechanisms once CO2 is injected.

Quantum simulation of zero-temperature quantum phases and incompressible states of light via non-Markovian reservoir engineering techniques

We review recent theoretical developments on the stabilization of strongly correlated quantum fluids of light in driven-dissipative photonic devices through novel non-Markovian reservoir engineering techniques. This approach allows to compensate losses and refill selectively the photonic population so to sustain a desired steady-state. It relies in particular on the use of a frequency-dependent incoherent pump which can be implemented, e.g., via embedded two-level systems maintained at a strong inversion of population. As specific applications of these methods, we discuss the generation of Mott Insulator (MI) and Fractional Quantum Hall (FQH) states of light. As a first step, we present the case of a narrowband emission spectrum and show how this allows for the stabilization of MI and FQH states under the condition that the photonic states are relatively flat in energy. As soon as the photonic bandbwidth becomes comparable to the emission linewidth, important non-equilibrium signatures and entropy generation appear. As a second step, we review a more advanced configuration based on reservoirs with a broadband frequency distribution, and we highlight the potential of this configuration for the quantum simulation of equilibrium quantum phases at zero temperature with tunable chemical potential. As a proof of principle we establish the applicability of our scheme to the Bose-Hubbard model by confirming the presence of a perfect agreement with the ground-state predictions both in the Mott Insulating and superfluid regions, and more generally in all parts of the parameter space. Future prospects towards the quantum simulation of more complex configurations are finally outlined, along with a discussion of our scheme as a concrete realization of quantum annealing.

Internal dissipation and heat leaks in quantum thermodynamic cycles.

The direction of the steady-state heat currents across a generic quantum system connected to multiple baths may be engineered to realize virtually any thermodynamic cycle. In spite of their versatility, such continuous energy-conversion systems are generally unable to operate at maximum efficiency due to non-negligible sources of irreversible entropy production. In this paper we introduce a minimal model of irreversible absorption chiller. We identify and characterize the different mechanisms responsible for its irreversibility, namely heat leaks and internal dissipation, and gauge their relative impact in the overall cooling performance. We also propose reservoir engineering techniques to minimize these detrimental effects. Finally, by looking into a known three-qubit embodiment of the absorption cooling cycle, we illustrate how our simple model may help to pinpoint the different sources of irreversibility naturally arising in more complex practical heat devices.

Quantum Brownian magneto-oscillator: Role of environmental spectrum and external magnetic field in decoherence and decay processes

In this work, we consider the dissipative dynamics of a quantum Brownian magneto-oscillator in contact with different types of environment at zero temperature as well as at high temperatures. We derive closed-form expressions of decay rate and heating rate for the magneto-oscillator in contact with Ohmic, sub-Ohmic, and super-Ohmic environments with non-Markovian characteristics. The present study is useful in determining the relationship between the thermalization dynamics of a magneto-oscillator and different forms of environmental spectrum and external magnetic field. Although our study is limited to the short-time (Non-Markovian) and long-time (Markovian) regimes, it manifests that one can actually tune the effective coupling of the system reservoir either by tuning oscillator frequency through reservoir engineering techniques or changing external magnetic field. Thus the present work establishes the essential role of non-Markovian dissipation and the crucial role of magnetic field in the environment induced decoherence and decay processes of the dissipative magneto-oscillator.

Quantum-enhanced absorption refrigerators

Thermodynamics is a branch of science blessed by an unparalleled combination of generality of scope and formal simplicity. Based on few natural assumptions together with the four laws, it sets the boundaries between possible and impossible in macroscopic aggregates of matter. This triggered groundbreaking achievements in physics, chemistry and engineering over the last two centuries. Close analogues of those fundamental laws are now being established at the level of individual quantum systems, thus placing limits on the operation of quantum-mechanical devices. Here we study quantum absorption refrigerators, which are driven by heat rather than external work. We establish thermodynamic performance bounds for these machines and investigate their quantum origin. We also show how those bounds may be pushed beyond what is classically achievable, by suitably tailoring the environmental fluctuations via quantum reservoir engineering techniques. Such superefficient quantum-enhanced cooling realises a promising step towards the technological exploitation of autonomous quantum refrigerators.

Interview with 2014 SPE President Jeff Spath

2014 SPE President Jeff Spath Jeff Spath is a member of the Schlumberger executive management team as vice president of industry affairs and is the 2014 SPE President. He will take office during the 2013 SPE Annual Technical Conference and Exhibition, to be held 30 September–2 October in New Orleans. Previously, he was president of the Schlumberger Reservoir Management Group and was president of Data and Consulting Services. He began his career with Flopetrol-Johnston Schlumberger as a field engineer conducting well tests onshore and offshore Louisiana and has worked for 30 years in various global positions in reservoir engineering, research, and management. Spath is a recognized leader in the development and application of reservoir engineering and production enhancement techniques, including well testing, reservoir simulation, and nodal analysis. He is the author or coauthor of nearly 30 peer-reviewed publications and holds 14 patents. An SPE member since 1983, Spath has served on many SPE committees and in many sections around the world. He was a Distinguished Lecturer during 1999–2000 and served as Technical Director of Management and Information during 2005–2008. He was elected an SPE Distinguished Member in 2011. Spath also currently serves on the Management Committee of the International Association of Oil & Gas Producers; the petroleum engineering advisory boards at Texas A&M University, the Colorado School of Mines, and the Natural Petroleum Council; and on the United Nations Global Energy Board. Spath earned BS and MS degrees in petroleum engineering from Texas A&M University and a PhD degree in reservoir engineering from the Mining University of Leoben in Austria. What are your goals as SPE president? One goal would be to further globalize the Society. There is no doubt that SPE has made huge strides internationally from what was once a predominantly North American member society in the 1970s and 1980s. Today, more than half of our members reside outside North America. We have to continue to follow the upstream oil and gas business to the new frontiers, the new basins, and the new regions of exploration such as Greenland, east Africa, and the Caspian. Not just for the sake of member growth, but to make SPE more local and more relevant by adding professional sections and student chapters so critical to achieving success—both for industry and for individuals—in these new regions. Secondly, we need to increase the degree to which SPE engages and collaborates with other organizations. We all accept that reservoirs are becoming more challenging to dis-cover and produce. They are smaller, more complex, and they exist in increasingly hostile terrains under more difficult temperatures and pressures. Not to mention the challenges created by nanoperm shales and ultraheavy oil.

Integrated Dynamic-Flow Analysis To Characterize an Unconventional Reservoir

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 156163, ’Integrated Dynamic-Flow Analysis To Characterize an Unconventional Reservoir in Argentina: The Loma La Lata Case,’ by Matias Fernandez Badessich and Vicente Berrios, YPF, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. In November 2010, YPF brought the first shale-oil well on line in Argentina in the Loma La Lata field after fracturing the Vaca Muerta formation, the main source rock in the Neuquen basin. Production forecasting and reserves estimation in this kind of reservoir are fraught with challenges. Several reservoir- and production-analysis techniques were applied, including pressure-transient analysis (PTA), rate-transient analysis (RTA), interpretation of available diagnostic-fracture-injectivity tests (DFITs), and time-lapsed production logging. YPF implemented a workflow to analyze dynamic data that capture the physics of the flow process, to explain the observed data, and to forecast reserves for a range of assumed in-place volumes. Introduction The formation in this field has a thickness range of 25 m in the proximal areas to 450 m at the basin center. Formation depth ranges from less than 1000 m at the basin margin to 4000 m near the basin center. With the wide areal distribution and variable thickness and over-burden, the Vaca Muerta has produced low-gas/oil-ratio liquid hydrocarbons, volatile oils, gas with condensate, and dry gas. According to log and core analysis, the matrix porosity of the Vaca Muerta shale varies from 4 to 14%, with an average of 9%, while matrix permeabilities span from hundreds of nanodarcies to production rates. At the time this paper was written, 27 vertical wells and three horizontal wells in this field had been placed on production. Most of the wells required massive hydraulic fractures to achieve commercial rates. Typically, four fracture stages were performed in the vertical wells, while 10 stages were completed in the approximately 1000-m-long horizontals. More than 100 fracture treatments were completed, with a very small percentage of screenouts. Approximately 30% of the wells penetrated “sweet spots” where the upper Vaca Muerta appears to be naturally fractured, and these wells produce without stimulation. After these high-pressure/high-productivity zones are penetrated, drilling operations can hardly continue because the wells become very difficult to control. At that point, the bottom-hole assembly is retrieved and the well is completed open hole. Data-Acquisition Plan The data-gathering strategy was to capture the right information at the right time. The collection plan involved acquiring the following static and dynamic data. Core and log data Geomechanical studies DFITs in key wells Microseismic monitoring Wellhead pressures and temperatures during production Downhole pressures and temperatures by use of retrievable downhole gauges Time-lapsed production-logging surveys Full chemical analysis of the oil, gas, and water Tracer analysis With this information at hand and with the goal of integrating all the available information, several reservoir-engineering techniques were applied to estimate the expected range of ultimate recovery per well.

Integrated production modelling of the Wheatstone-Iago fields: boon or bane?

Applying integrated production modelling (IPM) for decision making in the oil and gas industry has proliferated rapidly, evidenced by the amount of published information about successful applications of this approach. A reason for its popularity is to mitigate the risk of over(under)investment, which is driving asset teams toward jettisoning the practice of using fixed THP to account for backpressure effects or to use the limited surface network options available in most numerical reservoir simulators. This extended abstract describes the modelling of an offshore gas development by coupling multiple full-field, numerical reservoir simulation models with a shared surface network model. Such an approach enabled subsurface elements of the production system to be linked directly to surface elements (subsea and platform) yielding a fully coupled IPM. Key development decisions were tested and justified in a technically rigorous and economically robust manner. These decisions included the phasing of development wells, compression requirements and flow balancing in the pipeline system to maintain specified gas delivery rates. Experience from this approach has shown traditional reservoir engineering techniques can still yield the same outcome as an IPM with comparable accuracy—for some development decisions such as using a creaming curve and fixed THP to determine optimum well count; nevertheless, using simple methods to account for backpressure effects may not allow the same broad-based integration of design requirements needed at the design and engineering stage of large-scale projects. The PowerPoint presentation is not available to APPEA.

A new practical approach in modelling and simulation of shale gas reservoirs: application to New Albany Shale

The intent of this study is to reassess the potential of New Albany Shale formation using a novel and integrated workflow, which incorporates natural fracture system modeling with top-down intelligent reservoir modelling technique. Top-down, intelligent reservoir modeling technology integrates reservoir engineering analytical techniques with artificial intelligence and data mining in order to arrive at an empirical, cohesive and spatiotemporally calibrated full field model. The model is used to predict reservoir performance. Analytical reservoir engineering techniques used in the top-down modelling presented in this study include production decline analysis, type curve matching, single well history matching, volumetric reserve and recovery factor estimations are integrated with Voronoi graph theory, geostatistics, two-dimensional fuzzy pattern recognition, and discrete, data driven predictive modelling. The resulting full field top-down modeling is used to identify the distribution of the remaining reserves, sweet spots for infill locations, under-performer wells and also prediction of new well’s performance.

OPTIMIZING THE HC RECOVERY ALONG WITH CO 2 STORAGE

Several strategies were tested and studied to find injection and production procedures that “cooptimize” oil recovery and CO 2 storage. The results show that traditional reservoir engineering techniques such as injecting CO 2 and water in a sequential, so-called water-alternating-gas process are not conducive to maximize CO 2 stored within the reservoir. A well control process that shuts in wells producing large volumes of gas and allows shut-in wells to open as reservoir pressure increases was a successful strategy for co-optimization. This result holds for immiscible and miscible gas injection and can be improved when miscible gas injection is followed by pure CO 2 injection. Combining this strategy with well-control technique produced the maximum amount of oil and simultaneously stored the most CO 2 giving robust results.

Insight Into Integrated Reservoir Management Using a Top-Down Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 132621, ’New Insight Into Integrated Reservoir Management Using a Top- Down, Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field in the Middle East,’ by Amirmasoud Kalantari- Dahaghi, Shahab D. Mohaghegh, and Yasaman Khazaeni, SPE, West Virginia University, prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed. Top-down intelligent reservoir modeling (TDIRM) integrates reservoir-engineering analytical techniques with artificial intelligence and data mining to arrive at an empirical, cohesive, and spatiotemporally calibrated full-field model. The model is used to predict reservoir performance to recommend field-development strategies. Introduction TDIRM attempts to provide insight into fluid flow in the reservoir by starting with field measurements such as well-production history and well logs. Other data such as core analysis, well tests, and seismic can be used to increase model accuracy. Although not intended as a substitute for conventional reservoir simulation of large complex fields, this approach to reservoir modeling and management can be used as an alternative to traditional reservoir simulation and modeling for cases in which performing conventional modeling is cost and manpower prohibitive. If a conventional model already exists, TDIRM may complement the conventional technique with an independent assessment of the reservoir/well data to optimize development-strategy and recovery enhancement. In this study, TDIRM was performed on a giant complex oil field in the Middle East that has produced for a half-century. The reservoir has produced under natural depletion, with a strong waterdrive maintaining reservoir energy. The formation is a complex mix of clastics and carbonates of variable reservoir quality. This prolific reservoir has highly complex flow behavior. Methodology TDIRM uses accepted reservoir-engineering techniques such as decline-curve analysis, type-curve matching, (single-well) production-history matching, volumetric-reserves estimation, and calculation of recovery factors. These analyses are performed on individual wells. By use of statistical techniques, multiple production indicators [i.e., first 3-, 6-, and 9-month cumulative production and the 1-, 3-, 5-, and 10-year cumulative oil, gas, and water production and gas/oil ratio (GOR) and water cut] are calculated. To model the behavior of nondeclining-production characteristics such as GOR and water cut, intelligent decline-curve analysis is performed on GOR for which a negative decline is normal behavior. Intelligent decline-curve analysis is specific to TDIRM, and it is performed by use of an adaptive time-series-modeling technique that trains itself with existing data and predicts system behavior for a specific length of time into the future.

Accelerating CO2 Dissolution in Saline Aquifers for Geological Storage — Mechanistic and Sensitivity Studies

One of the important challenges in geological storage of CO2 is predicting, monitoring, and managing the risk of leakage from natural and artificial pathways such as fractures, faults, and abandoned wells. The risk of leakage arises from the buoyancy of free-phase mobile CO2 (gas or supercritical fluid). When CO2 dissolves into formation brine, or is trapped as residual phase, buoyancy forces are negligible and the CO2 may be retained with minimal risk of leakage. Solubility trapping may therefore enable more secure storage in aquifer systems than is possible in dry systems (e.g., depleted gas fields) with comparable geological seals. A crucial question for an aquifer system is, what is the rate of dissolution? In this paper, we address that question by presenting a method for accelerating CO2 dissolution in saline aquifers by injecting brine on top of the injected CO2. We investigate the effects of different aquifer properties and determine the rate of solubility trapping in an idealized aquifer geometry. The acceleration of dissolution by brine injection increases the rate of solubility trapping in saline aquifers and therefore increases the security of storage. We show that, without brine injection, only a small fraction (less than 8%) of the injected CO2 would be trapped by dissolving in formation brine within 200 years. For the particular cases studied, however, more than 50% of the injected CO2 dissolves in the aquifer as induced by brine injection. Since the energy cost for brine injection can be small (<20%) compared to the energy required for CO2 compression for a 5-fold increase in dissolution, such reservoir engineering techniques might be viable and practical for accelerating dissolution of CO2. The environmental benefit would be to decrease the risk of CO2 leakage at reasonably low cost.

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.

Application of hydrodynamics to sub-basin-scale static and dynamic reservoir models

In mature hydrocarbon provinces, the impact of production induced pressure depletion on un-produced or undiscovered reserves is a concern. Reduced formation pressure has an adverse effect on recoverability, but more problematic are accumulations that are filled to spill, where a reduction of formation pressure results either in gas exsolution or gas cap expansion and loss of liquids from the trap. In the Australian context, the latter is of significant concern owing to the gas rich nature of many of its sedimentary basins. Standard reservoir engineering techniques have been used to evaluate the impact of pressure depletion with mixed results. There are three assumptions typically made in the reservoir models that are normally valid for a single pool, but can add significant uncertainty when applied to a region of several pools, or worse yet, at the sub-basin or basin-scale. The first assumption is that the virgin pressure state of the aquifer at the base of the hydrocarbon column can be approximated by an average hydrostatic formation water pressure gradient. The second is that all pressure data can be referenced to a common reservoir datum by correcting each measured formation pressure using an assumed fluid pressure gradient. The third is that the aquifer which supports one or more hydrocarbon pools has a fixed volume. The study of basin hydrodynamics uses techniques that take into account the fact that, while the pre-production trapped hydrocarbon phase is static, the aquifer at the base of the hydrocarbon accumulation is dynamic. Regional boundary conditions can be identified that drive formation water flow and help define formation water influx and discharge from an aquifer system rather than assuming a fixed aquifer volume. Pressures in an aquifer may therefore vary for a given depth, due to variations in the hydraulic potential field resulting from differences in aquifer properties across a sub-basin. Hydrodynamic techniques also characterise formation pressure data using a hydraulic head to avoid the requirement of referencing a formation pressure to a depth datum. It removes the need to assume a particular fluid pressure gradient when the fluid composition is not known. This paper describes how hydrodynamic techniques can be incorporated into the static and dynamic reservoir models to reduce errors and uncertainty in the model results. These include the use of a potentiometric energy distribution for the aquifer to obtain aquifer pressure rather than an average hydrostatic gradient and a basin wide depth datum, and the characterisation of natural inflows and discharges rather than assuming a fixed aquifer volume. The approach is exemplified with data from various basins.

Geologic storage of carbon dioxide and enhanced oil recovery. II. Cooptimization of storage and recovery

Abstract Geologic sequestration of carbon dioxide (CO2) in oil and gas reservoirs is one possibility to reduce the amount of CO2 released to the atmosphere. Carbon dioxide injection has been used in enhanced oil recovery (EOR) processes since the 1970s; the traditional approach is to reduce the amount of CO2 injected per barrel of oil produced. For a sequestration process, however, the aim is to maximize both the amount of oil produced and the amount of CO2 stored. It is not readily apparent how this aim is achieved in practice. In this study, several strategies are tested via compositional reservoir simulation to find injection and production procedures that “cooptimize” oil recovery and CO2 storage. Flow simulations are conducted on a synthetic, three dimensional, heterogeneous reservoir model. The reservoir description is stochastic in that multiple realizations of the reservoir are available. The reservoir fluid description is compositional and incorporates 14 distinct components. The results show that traditional reservoir engineering techniques such as injecting CO2 and water in sequential fashion, a so-called water-alternating-gas process, are not conducive to maximizing the CO2 stored within the reservoir. A well control process that shuts in (i.e. closes) wells producing large volumes of gas and allows shut in wells to open as reservoir pressure increases is the most successful strategy for cooptimization. This result holds for both immiscible and miscible gas injection. The strategy appears to be robust in that full physics simulations employing multiple realizations of the reservoir model all confirmed that the well control technique produced the maximum amount of oil and simultaneously stored the most CO2.

A mass balance approach for assessing basin-centred gas prospects: integrating reservoir engineering, geochemistry and petrophysics

Abstract This paper presents a mass balance technique for evaluating the resource-in-place potential of basin-centred gas exploration prospects. As the name implies, the methodology is derived from the conservation of mass principle. Unlike conventional reservoir engineering techniques, the mass balance approach directly integrates dynamic elements of the total petroleum system with all static reservoir engineering, geological and petrophysical data to estimate the resource-in-place. This prospect evaluation technique not only provides an independent estimate of hydrocarbon resource-in-place for comparison with that computed from the conventional reservoir engineering approach, but also gives estimates of hydrocarbons lost from the petroleum system. Accordingly, this technique reduces the inherent uncertainty associated with conventional methods and provides more realistic estimates of resource-in-place.