Reservoir Performance Analysis Research Articles

Applications of Asymptotic Solutions of the Diffusivity Equation to Infinite Acting Pressure Transient Analysis

Summary Understanding how pressure propagates in a reservoir is fundamental to the interpretation of pressure and rate transient measurements at a well. Unconventional reservoirs provide unique technical challenges as the simple geometries and flow regimes [wellbore storage (WBS) and radial, linear, spherical, and boundary-dominated flow] applied in well test analysis are now replaced by nonideal flow patterns due to complex multistage fracture completions, nonplanar fractures, and the interaction of flow with the reservoir heterogeneity. In this paper, we introduce an asymptotic solution technique for the diffusivity equation applied to pressure transient analysis (PTA), in which the 3D depletion geometry is mapped to an equivalent 1D streamtube. This allows the potentially complex pressure depletion geometry within the reservoir to be treated as the primary unknown in an interpretation, compared with the usual method of interpretation in which the depletion geometry is assumed and parameters of the formation and well are the unknown properties. The construction is based upon the solution to the Eikonal equation, derived from the diffusivity equation in heterogeneous reservoirs. We develop a Green’s function that provides analytic solutions to the pressure transient equations for which the geometry of the flow pattern is abstracted from the transient solution. The analytic formulation provides an explicit solution for many well test pressure transient characteristics such as the well test semi-log pressure derivative (WTD), the depth of investigation (DOI), and the stabilized zone (SZ) (or dynamic drainage area), with new definitions for the limit of detectability (LOD), the transient drainage volume, and the pseudosteady-state (PSS) limit. Generalizations of the Green’s function approach to bounded reservoirs are possible (Wang et al. 2017) but are beyond the scope of the current study. We validate our approach against well-known PTA solutions solved using the Laplace transform, including pressure transients with WBS and skin. Our study concludes with a discussion of applications to unconventional reservoir performance analysis for which reference solutions do not otherwise exist.

Reservoir performance analysis through the material balance equation: An integrated review based on field examples

The Material Balance Equation (MBE) has proved its versatility over a century because it has been adapted to include several production mechanisms identified in homogeneous, naturally fractured, and unconventional reservoirs. Thus, numerous field cases regarding the practical use of the MBE are found in the Petroleum Engineering literature. However, those cases have been analyzed by using diverse approaches introduced at different times, leading to a wide variety of analysis methods. Several field examples are revisited in this work through an integrated review that properly uses analysis techniques focused on diagnostics, straight-line analysis, and pressure-production history matching. This review provides additional insights about the reservoir performance compared to the results presented in the original papers. Thus, the conceptual model of the reservoir-aquifer system is consistently characterized by using several graphs along the process of analysis. The reasons related to the complementary role between the conventional straight-line analysis and the history matching technique are provided; the latter should confirm the results from the straight-line analysis, while this one should guide the history matching technique. Also, based on the observation that a good history match does not guarantee the correct characterization of the reservoir-aquifer model, the relevance of integrating the Material Balance analysis with other disciplines is discussed. The significance of the multidisciplinary approach to mitigate the non-uniqueness inverse problem is illustrated through the study of complex examples, such as a naturally fractured reservoir connected to an aquifer. Furthermore, scrutiny on the concept of total effective formation-water compressibility is provided to emphasize the similarities and differences in the analysis of homogeneous and naturally fractured reservoirs through the MBE. • A comprehensive review of the material balance equation is presented through the analysis of field examples. • A standardized methodology for reservoir-aquifer characterization is applied in four field cases. • Different types of reservoirs are addressed: homogeneous and naturally-fractured oil and gas reservoirs. • The applicability of diverse unsteady state aquifer models is illustrated. • The concept of total effective formation-water compressibility is derived and examined.

A Novel Dynamic Splitting Method for Production Based on Material Balance Theory and Catastrophe Theory in Tight Gas Reservoirs

Splitting methods play a significant role in the coproduction of tight reservoirs which are characterized by vertical multilayer superimposition. It directly affects the accuracy of reservoir performance analysis and detailed descriptions. However, conventional splitting methods are limited to a few factors and static factors without considering the effect of layer parameter change. In this study, sensitivity analysis was carried out on five factors that affect the production splitting in coproduction wells. The research shows that in the production process, multiple parameters have a direct impact on the production of layers. Different parameters, which have to be included to split production, have different scale effects on layer production. Comparing the results of the KH method with the numerical simulation results, the limitation of the KH method for yield splitting is illustrated. A novel dynamic splitting method for production (DPSM) was proposed. This method is based on two primary methods, which are the multifactor static method for production splitting of gas (GPSM) and water (WPSM) and use the catastrophe theory and material balance equation (MBE) and obtain the final results by iterative method. The advantage of this method is that more accurate results in the production process are obtained by selecting eight factors, which contain 6 static factors and 2 dynamic factors, for research. It is more in line with the production practice that the ultimate results of production splitting vary with the production process. The accuracy and practicality of the results had been verified by numerical simulation. This method has practical significance for production splitting in tight gas reservoirs.

Computing Pressure Front Propagation Using the Diffusive-Time-of-Flight in Structured and Unstructured Grid Systems via the Fast-Marching Method

SummaryDiffusive-time-of-flight (DTOF), representing the travel time of pressure front propagation, has found many applications in unconventional reservoir performance analysis. The computation of DTOF typically involves upwind finite difference of the Eikonal equation and solution using the fast-marching method (FMM). However, the application of the finite difference-based FMM to irregular grid systems remains a challenge. In this paper, we present a novel and robust method for solving the Eikonal equation using finite volume discretization and the FMM.The implementation is first validated with analytical solutions using isotropic and anisotropic models with homogeneous reservoir properties. Consistent DTOF distributions are obtained between the proposed approach and the analytical solutions. Next, the implementation is applied to unconventional reservoirs with hydraulic and natural fractures. Our approach relies on cell volumes and connections (transmissibilities) rather than the grid geometry, and thus can be easily applied to complex grid systems. For illustrative purposes, we present applications of the proposed method to embedded discrete fracture models (EDFMs), dual-porosity dual-permeability models (DPDK), and unstructured perpendicular-bisectional (PEBI) grids with heterogeneous reservoir properties. Visualization of the DTOF provides flow diagnostics, such as evolution of the drainage volume of the wells and well interactions.The novelty of the proposed approach is its broad applicability to arbitrary grid systems and ease of implementation in commercial reservoir simulators. This makes the approach well-suited for field applications with complex grid geometry and complex well architecture.

Reservoir Development by Waterflooding and Reservoir Performance Analysis

With the rapid development of China's society and economy, relevant industries get good development opportunities, and the demand for oil is increasing. The oil production in the oilfield is increasing day by day. At present, most oilfields gradually enter the middle and late stage of water injection exploitation, which increases the exploitation difficulty and reduces the exploitation amount. In this paper, a comprehensive analysis of waterflooding reservoirs and reservoir performance is made to promote better and faster development of petroleum industry.

Technology Focus: Reservoir Performance (September 2019)

Technology Focus Since the last Reservoir Performance feature in September 2018, complex supply- and-demand challenges have continued to shape our technology and business-innovation models. Under significant pressure from several angles, operators around the world are focusing on lowering their production costs for both conventional and unconventional assets, while oilfield service companies are responding to customers’ cost-saving requests with incremental improvements in technology, supply chains, automation, and collaboration. While the current trends in machine learning and artificial intelligence certainly can help lower the production costs, future reservoir-performance improvements still will have to rely on reservoir characterization, surveillance, and optimization. The current quest for production-cost savings cannot continue without improvements in both operational efficiency and recovery factors. In the past 12 months, 133 technical papers were presented at various conferences and meetings with a reservoir-performance focus and were reviewed for this feature, showcasing further advances in reservoir-performance monitoring, analysis, and optimization. For comparison, 157 and 160 technical papers were reviewed for the 2018 and 2017 features, respectively. Interestingly, this year, 39 papers had first authors from academia, 63 had first authors from operating companies, and 31 had first authors from oilfield service companies and consulting firms. For comparison, the review for the 2018 feature included 62 papers with first authors from academia, 70 with first authors from operating companies, and 25 with first authors from oilfield service companies and consulting firms. The three primary papers selected and three alternative papers recommended as additional reading constitute a representative sample of the 133 papers reviewed for this feature. They are a geographically diverse mix of fundamental research, industrial research and development, and field-application studies, reporting the latest reservoir-performance advances. Recommended additional reading at OnePetro: www.onepetro.org. SPE 192881 Reservoir Health Indicators Driving Performance Through Data Analytics by Mohamed Al Marzouqi, ADNOC, et al. SPE 193701 Satellite INSAR Technology for Caprock-Integrity Monitoring of Cyclic Steam Stimulation and Steamflooding Heavy-Oil Production in Kuwait by Zu Biao Ren, Kuwait Oil Company, et al. SPE 195366 Permeability and Porosity Evolution of Organic-Rich Shales as a Result of Heating by Tae Wook Kim, Stanford University, et al.

Guest Editorial: Growth in Unconventional Resources Adds to Technical Literature

Guest editorial Unconventional resources require technologies typically not used to produce conventional oil and gas reservoirs. In particular, starting in the late 1990s, the combination of horizontal wells and multistage hydraulic fracturing has been key to rapidly increasing success in exploiting unconventional resources. While the well completions in unconventional resources may be more expensive than those typically applied in conventional reservoirs, the advantage is access to the very large volumes of these resources, which include tight (low-permeability) gas in sandstone or carbonate rock, coalbed methane, and organic-rich source rocks classed as shale gas and tight oil. The exploitation of shale gas, along with tight gas and coalbed methane, enabled a stunning increase in US natural gas production of approximately 4 Tcf/D from 2005 to 2010. A similar story followed a few years later for US crude oil production. Tight oil production ramped up nearly 5 million B/D over approximately 5 years, starting in 2008, and continues to rise. And it is not just the US that is benefiting—unconventional resource development is now beginning to spread to other countries around the world. The technologies that accomplished these near miracles were developed, implemented, and continue to be improved largely by SPE members, and this has been reflected in an upsurge in conference presentations and journal publications related to unconventional resources over the past decade. This is illustrated by the chart (Fig. 1), which shows a dramatic increase in the percentage of peer-reviewed papers related to unconventional resources published in SPE Reservoir Evaluation & Engineering (SPEREE) beginning in 2011. Before 2011, there were only a handful of publications related to unconventional resources each year, primarily dealing with coal-bed methane and fundamentals of fluid flow in tight pore systems. Beginning in 2011, publications related to the analysis and prediction of shale gas reservoir production performance showed a sharp increase, followed a few years later by publications related to tight oil reservoir performance analysis and prediction. In addition, enhanced oil recovery from tight oil reservoirs has become an increasing area of focus. This year, over half of the publications in SPEREE will be related to unconventional resources. As further indication of the increasing importance of unconventional resources, in July SPE released Unconventional Gas and Tight Oil Exploitation, the first SPE monograph devoted exclusively to the topic.

Technology Focus: Reservoir Performance and Monitoring (September 2018)

Technology Focus Since the last Reservoir Performance and Monitoring feature in 2017, the industry has continued to advance with innovation in technology and business models to drive sustainable change. Operators around the world have continued lowering production costs aggressively, and oilfield service companies have continued to survive by making a low-margin profit in a greatly competitive market. If the industry until recently was lamenting an oversupply of oil and that a global upstream investment slump caused a focus on incremental technology improvements with fewer capital resources and personnel, now a looming oil-supply shortage has reignited discussions about how innovation, digital technologies, and collaborations can accelerate future major project development. In the last 12 months, 157 technical papers were presented at various conferences and meetings with reservoir performance and monitoring programs and were reviewed for this feature. For comparison, 160 were reviewed for the 2017 feature. Interestingly, 62 papers had first authors from academia, 70 from operating companies, and 25 from oilfield services companies and consulting firms. Sixty-three papers had authors with different affiliations. The six papers selected and recommended as additional reading are a representative sample of the papers reviewed for this feature. They are a geographically diverse mix of fundamental research, industrial research and development, and field-application studies, reporting the latest published advances in reservoir-performance monitoring, analysis, and optimization. In considering the 157 technical papers reviewed for this feature, I am looking forward to seeing how our industry is going to react through innovation and digital technologies to the supply and demand changes of coming years. A new era of operational efficiency improvements, improved recovery factors, and lower production costs from continuous reservoir performance monitoring, analysis, and optimization is ready to begin. Recommended additional reading at OnePetro: www.onepetro.org. SPE 188890 Effect of Irreversible Retention on Tracer Deployments: Constraining Novel Material Deployments by Hsieh Chen, Aramco, et al. SPE 189846 Applying Subsurface DNA Diagnostics and Data Science in the Delaware Basin by J. Silva, Anadarko, et al. SPE 190480 Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems by Ram R. Ratnakar, Shell, et al.

Water, energy and agricultural landuse trends at Shiroro hydropower station and environs

Abstract. The study examines the interplay among water resources, hydropower generation and agricultural landuse at the Shiroro hydropower station and its environs, in north-central Nigeria. Non-parametric trend analysis, hydropower footprint estimation, reservoir performance analysis, change detection analysis, and inferential statistics were combined to study the water-energy and food security nexus. Results of Mann–Kendall test and Sen's slope estimator for the period 1960 to 2013 showed a declining rainfall trend at Jos, around River Kaduna headwaters at −2.6 mm yr−1, while rainfall at Kaduna and Minna upstream and downstream of the reservoir respectively showed no trend. Estimates of hydropower footprint varied between 130.4 and 704.1 m3 GJ−1 between 1995 and 2013. Power generation reliability and resilience of the reservoir was 31.6 and 38.5 % respectively with year 2011 being the most vulnerable and least satisfactory. In addition to poor reliability and resilience indices, other challenges militating against good performance of hydropower generation includes population growth and climate change issues as exemplified in the downward trend observed at the headwaters. Water inflow and power generation shows a weak positive relationship with correlation coefficient (r) of 0.48, indicating less than optimal power generation. Total area of land cultivated increased from 884.59 km2 in 1986 prior to the commissioning of the hydropower station to 1730.83 km2 in 2016 which signifies an increased contribution of the dam to ensuring food security. The reality of reducing upstream rainfall amount coupled with high water footprint of electricity from the reservoir, therefore requires that a long term roadmap to improve operational coordination and management have to be put in place.

Key aspects of numerical analysis of gas hydrate reservoir performance: Alaska North Slope Prudhoe Bay Unit “L-Pad” hydrate accumulation

In previous work, we reported the development of the 3D geostatistical hydrate reservoir model of "L-Pad" (Myshakin et al., 2016). In this paper, gas production sensitivity on key reservoir parameters are studied. Hydraulic communication with an aquifer and optimal depressurization strategies are subjects of investigation. Uncertainty in initial in situ permeability within 0.1–10 mD range leads to 2.0 × 108–3.5 × 108 ST m3 of gas produced over 10 years. Accounting for reservoir quality and irreducible water saturation leads to noticeable change in productivity. Sequential depressurization of hydrate-bearing units was found to be more attractive versus simultaneous depressurization.

Technology Focus: Reservoir Performance and Monitoring (September 2017)

Technology Focus Since the last Reservoir Performance and Monitoring feature in September 2016, the industry trends of significantly improving efficiency and reducing operational costs have continued to be implemented. For instance, at the time of writing, in North America, the US oil rig count has risen impressively for 23 straight weeks and the big players have greatly reduced their exposure to Canada’s oil sands. However, while many efforts are focusing on the optimization of current technologies and the study of past reservoir performance to improve future developments, with fewer capital resources and personnel available, these efforts may yield only incremental improvements. Technology and innovation are seen industrywide as critical to long-term radical efficiency and productivity. Once the industry becomes less concerned about cost savings and more about investing in future technologies and long-term performance, the nonrisk-averse innovation culture from other industries could help us develop new disruptive technologies and implement them in the field. For instance, with the proper resources in place, automated reservoir-performance modeling and monitoring may no longer be a science-fiction scenario. Once this downturn appears in the rear-view mirror, our industry will need to change its model disruptively to thrive sustainably in the next growth cycle. During the past 12 months, 160 technical papers were presented at various conferences and meetings with reservoir-performance-and-monitoring programs and were reviewed for this feature, displaying further advances in reservoir-performance monitoring, analysis, and optimization. The papers selected and recommended as additional reading are representative samples of the reviewed papers. They are a geographically diverse mix of academic work, industrial research and development, and field applications, describing numerical simulation and laboratory research, field-data-acquisition and -interpretation studies, new-technology development and field trials, and multi-year reviews of current technologies and work flows. Recommended additional reading at OnePetro: www.onepetro.org. SPE 181550 Current State and Future Trends in the Use of Downhole Fluid Analysis for Improved Reservoir Evaluation by H. Elshahawi, Shell, et al. SPE 184131 Production Optimization Through Voidage Replacement Using Triggers for Production Rate by Cenk Temizel, Aera Energy, et al. SPE 183195 Development of Crosswell Electromagnetic Monitoring System Using the HTS-SQUID Magnetometer by Makoto Harada, Japan Oil, Gas, and Metals National Corporation, et al.

Technology Focus: Reservoir Performance and Monitoring (September 2016)

Technology Focus Since the last Reservoir Performance and Monitoring feature, in September 2015, unfavorable market conditions have significantly constrained the operating cash flow of energy companies worldwide. This has prompted a response to delay or cancel capital-intensive projects, improve efficiency, and reduce operating costs. The response to innovation of the industry to survive through this downturn and thrive afterward could be perceived as slow. However, despite the current downturn, the industry has seen further advancements in innovation, including in reservoir-performance monitoring, analysis, and optimization. As an indicator of these advancements, almost 240 technical papers presented in the past 12 months at various conferences and meetings with reservoir-performance- and-monitoring programs were reviewed for this feature, as compared with approximately 100 in the preceding year. The current reservoir-performance-monitoring technologies are being improved continuously for better reservoir understanding, more-accurate short- and long-term production forecasting, and lower overall operational costs. The industry is becoming more efficient at using existing technologies to improve mature-field performance and surveillance. For instance, new approaches and models have been presented recently for operational optimization and future-production-behavior predictions, especially in unconventional reservoirs. Interwell tracers have been evaluated in the laboratory for their applicability in different mineralogies, and their full-field implementation in carbonate reservoirs has been reported. Temperature and acoustic measurements with fiber-optic technologies have been reported to add value to heavy-oil- reservoir monitoring. New theoretical and experimental models at micro-and nanoscales have been proposed to improve the industry understanding of fluid/formation interaction. Integrated multidisciplinary work flows have been developed to increase the value of reservoir-data monitoring. The current advancements in efficiency and innovation should lead to future successes as market conditions improve. The papers selected and recommended as additional reading are representative samples of the reviewed papers for this feature and are intended to show diverse examples of implementing multiple concepts and methodologies for production evaluation and achieving better reservoir performance. They are a mixture of field and academic applications, from all regions of the world, reporting case histories, field-data acquisition and interpretation, work flows, theoretical models, and laboratory results. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 180369 Detecting Opal-CT Formation Resulting From Thermal Recovery Methods in Diatomites by C.M. Ross, Stanford University, et al. SPE 180061 Dynamic Reservoir Characterization and Production Optimization by Integrating Intelligent Inflow Tracers and Pressure-Transient Analysis in a Long Horizontal Well for the Ekofisk Field, Norwegian Continental Shelf by M. Prosvirnov, ConocoPhillips, et al. SPE 178984 Comprehensive Field-Scale Injection-Performance Analysis Associated With Injected-Water-Quality Parameters by Bangkog A. Sabut, Saudi Aramco, et al. OTC 26232 From Nanoscale Wetting Toward Enhanced Oil Recovery by R. Giro, IBM Research, et al.

Experimental and numerical analysis of reservoir performance for geological CO2 storage in the Ordos Basin in China

Unique reservoir performance was observed in the Shenhua 100,000t/year Carbon Capture and Storage (SHCCS) Demonstration Project. Suggested by the geological pre-assessments, hydraulic fracturing and a multi-layer injection procedure were employed to improve the injectivity and reduce the risk of an overpressure. However, in-situ data showed the total injection rate increased after the injection started, while the injection initiation pressure decreased with only a minor pressure build-up development. Additionally, the injectivity of the uppermost injection layer, which was not fractured, grew considerably over the years, making this layer potentially able to meet the target rate by itself. To clarify this unforeseen observation, the reservoir performance was investigated through numerical simulations and comparison against the 2.5-year historical data. The simulation results indicated that permeability heterogeneity of the injection layers might explain the observed reservoir performance. High CO2 injectivity in the uppermost injection layer could be attributed to its overall permeability being higher than that of other layers, and the considerable injectivity increase over the years could have been caused by the substantial permeability increase along the principal direction of CO2 migration in this layer. The injectivity improvement caused by hydraulic fracturing was significant in the early time of injection, but it dramatically reduced afterwards. The intermittent injection procedure could effectively reduce the pressure build-up in the reservoir and helped to maintain the injection at the target rate. Based on these assessments, the cumulative injected CO2 mass could reach 300,000t in December 2015, but the yearly average injection rate would drop slightly. The predicted cumulative mass could be underestimated because the higher injectivity in 2014 was not accounted for in the calibration, and because the model size could have affected the reservoir performance, as shown by the sensitivity analysis. This research indicated that permeability heterogeneity and the injection procedure could significantly affect the reservoir performance, and should be given consideration in the performance assessment.

Analysis of Hydraulic Fracturing and Reservoir Performance in Enhanced Geothermal Systems

Analyses of fracturing and thermal performance of fractured reservoirs in engineered geothermal system (EGS) are extended from a depth of 5 km to 10 km, and models for flow and heat transfer in EGS are improved. Effects of the geofluid flow direction choice, distance between fractures, fracture width, permeability, radius, and number of fractures, on reservoir heat drawdown time are computed. The number of fractures and fracture radius for desired reservoir thermal drawdown rates are recommended. A simplified model for reservoir hydraulic fracturing energy consumption is developed, indicating it to be 51.8–99.6 MJ per m3 fracture for depths of 5–10 km.

Technology Focus: Reservoir Performance and Monitoring (September 2014)

Technology Focus “If you have one watch, you know the time. If you have two, you will never be sure.” This was a quote that my professor in reservoir engineering, T.D. van Golf-Racht, once stated when he tried to make us students reflect upon the availability and the quality of the data given for a specific exercise. This was in the late 1980s, and the amount of data was rather limited compared with today’s vast amount of data available. The cost of new data is increasing; most operators are cutting cost, and the cost/ benefit exercise is getting more and more challenging. Actionable information is even more important, and payback time is the crucial number to know. When you have obtained the necessary funding for acquiring data, make sure that you spend it wisely by collecting the data the right way and understanding the data you have gathered. Paper SPE 169539, related to diagnostic fracture injection tests, highlights the pitfalls when acquiring data to prepare for a hydraulic-fracture treatment. Understanding well and reservoir performance is the ultimate goal of data gathering, and this gives the necessary foundation for making decisions. Regardless of the amount of data available and supercomputers at hand, analytical methods still play an important role in today’s analysis of reservoir performance. Another featured paper describes the use of modern analytical tools in an excellent way. Data are of particular importance when you try to establish fundamental knowledge, whether it is drainage strategy for a new discovery or (even more fundamental) recovery processes for new types of hydrocarbons such as hydrates, described in paper OTC 25328. We, the engineers, need to prepare for tougher times ahead. We need to make sure that key data are collected and be prepared to skip the rest. We need to make sure that more time is spent understanding the data than gathering them. We need to make sure that we perform cost/benefit analysis both before and after data acquisition. JPT

Development Characteristics and Development Adjustment Countermeasures of Wangji Oilfield

Wangji oilfield is a complicated fault-block oilfield, with many oil-bearing systems and severe heterogeneity. More and more problems and conflicts are exposed during the production and it is hard to produce the remaining oil, when entering into the medium-late water cut stage. In this paper, current development characteristics and main existing problems of Wangji oilfield are analyzed, including low development degrees of reserve, low recovery percent, low oil recovery rate, low perfecting degree of well pattern and so on. The combined research means of reservoir performance analysis and numerical simulation are used to analyze the distribution characteristics and rich region of remaining oil, then, the technology policies of vector well pattern[1] adjustment which is suitable for later development was put forward. Based on these, the injection-production system was adjusted, the injection - production corresponding relation was improved and the economic benefit was increased, which possesses reference meaning in the development of the similar oilfield in future.

Rebirth of a Mature Carbonate Gas Pool

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88773, "Rebirth of a Mature Carbonate Gas Pool," by K.C. Carr, SPE, and M. Fiori, BP Canada Energy Co., prepared for the 2004 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October. Operation of a mature pool requires increasing cost control and infrastructure optimization and consolidation to maintain profitability. The decision to initiate this type of reservoir-management plan, sometimes described as “harvest,” is driven in part by reservoir-performance analysis and in part by commodity prices. The full-length paper presents the account of a 3.7-Tcf sour-gas pool in Alberta, Canada, and the technical impact of harvest on field operations, reservoir performance, and ultimate recovery. The combination of new production-decline analysis and a well workover with surprising results led to a complete change in reservoir interpretation. Introduction Management of mature pools is not a new challenge. In the Western Canadian basin, the surge of exploration and development activity in the 1950s and 1960s has left a legacy of very mature pools, with many of these 40- to 50-year-old pools still producing. Records show that of the 30,000 gas pools discovered in Alberta, 2,000 were discovered before 1970. In the aggregate, these pools represent 15 Tcf of remaining recoverable reserves. Each of these pools was at some point declared mature on the basis of the science of the day and treated as a harvest candidate (i.e., a pool with very limited upside where the best strategy is to control cost and produce what is left without further investment).

Improving recovery from mature oil fields producing from carbonate reservoirs: Upper Jurassic Smackover Formation, Womack Hill field (eastern Gulf Coast, U.S.A.)

Reservoir characterization, modeling, and simulation were undertaken to improve production from Womack Hill field (eastern Gulf Coast, United States). This field produces oil from Upper Jurassic Smackover carbonate shoal reservoirs. These reservoirs occur in vertically stacked, heterogeneous depositional and porosity cycles. The cycles consist of lime mudstone and wackestone at the base and ooid grainstone at the top. Porosity has been enhanced through dissolution and dolomitization. Porosity is chiefly interparticle, solution-enlarged interparticle, grain moldic, intercrystalline dolomite, and vuggy pores. Dolostone pore systems and flow units have the highest reservoir potential. Petroleum-trapping mechanisms include a fault trap (footwall uplift with closure to the south against a major west-southeast–trending normal fault) in the western area, a footwall uplift trap associated with a possible southwest-northeast–trending normal fault in the south-central area, and a salt-cored anticline with four-way dip closure in the eastern area. Potential barriers to flow are present as a result of petrophysical differences among and within the cycles, as well as the presence of normal faulting. Reservoir performance analysis and simulation indicate that the unitized western area has less than 1 MMSTB of oil remaining to be recovered, and that the eastern area has 2–3 MMSTB of oil to be recovered. A field-scale reservoir management strategy that includes the drilling of infill wells in the eastern area of the field and perforating existing wells in stratigraphically higher porosity zones in the unitized western area is recommended for sustaining production from the Womack Hill field.

SAGD Injection Wells What Your Prof Never Told You

The intention of this article is threefold. The first is to provide some insight into the design of SAGD injection wells. This is a topic that has not yet been the subject of much formal literature. The second is to disseminate some of the more interesting aspects of non-linear dynamics supported by material from the real world analysis of SAGD injection well performance. The petroleum industry is only beginning to understand the substantial implications of non-linear dynamics. The potential effect on the prediction of SAGD performance is significant. Extensions to other fields of reservoir performance analysis are possible and probable. In the preface to the following material, it is important to recognize that numerical simulations of the SAGD process within existing numerical simulators provide results with acceptable or even superior accuracy, for most of engineering purposes. There are, however, fundamental limits to the current numerical simulation techniques used for SAGD processes. In this respect, the third objective of this article is to identify a few of this limitations. SAGD Injection Well Performance So you wish to inject steam into a SAGD injection well. Sounds pretty simple: just connect the wellhead piping to the surface steam supply and open the valve. Having some proper metering helps, but providing for this should be pretty routine. The only real issue is to the design the well to optimise the placement if the steam for the SAGD process. For the purposes of this article, the design constraints during pseudo-steady-state operation after approximately six months of operation are discussed. The challenges of the early start-up period during the first six months or so are not considered. Indeed, these early time constraints can be quite complex and are worthy of future discussion. The design constraints of pseudo-steady-state operation are framed by the desire for (in the author's estimation of importance):Drilling feasibilityLowest possible pressure drop along the horizontal annulus of the wellGood distribution of steam quality along the wellLowest drilling costRobust operating characteristics This article will be limited to addressing constraints 2, 3, and to some extent 5. Horizontal Annulus Pressure Drop Considerations The folklore of SAGD well design is to allow for up to 50kPa pressure drop(1) along the annulus of the horizontal section of the well. The idea is that the pressure drop along the well will be reflected in an uneven liquid level in the chamber as shown in FIGURE 1:Classical view of effects of pressure drop along the injector on the steam chamber liquid level. Available In Full Paper. Figure 1. Integral to the idea is the assumption of a production well with very little pressure drop in the horizontal annulus, creating a near constant pressure sink. By extension, if the fluid level covers the injection well, the adverse steam injection distribution is expected(2). Based on a typical 5m vertical spacing between the injection and production wells, the 50 kPa guideline is roughly equivalent to the gravitational head of the liquid.

Asymptotics, streamlines, and reservoir modeling: A pathway to production tomography

Today's geophysicists work ever more closely with reservoir engineers and geologists due to the advent of geophysical techniques for reservoir surveillance. Geophysicists have transcended their traditional task of exploration in order to monitor reservoir performance. They are thus called upon to understand the nature of fluid flow within a reservoir and the relationship between reservoir/fluid properties and geophysical observations. It would seem that the physics of fluid flow within a reservoir is, for the most part, unrelated to the phenomena traditionally studied by exploration geophysicists, such as wave propagation within the earth. However, while the physics of fluid flow and elastic-wave propagation are distinct, many shared concepts are extremely useful in reservoir characterization and performance analysis.