Horizontal-well Performance Research Articles

Characterization of tight-gas sand reservoirs from horizontal-well performance data using an inverse neural network

Characterization of a tight-gas sand formation using data from horizontal wells at isolated locations is challenging due to the inherent heterogeneity and very low permeability characteristics of this class of resources. Furthermore, characterizing the uncontrollable hydraulic-fracture properties along the horizontal wellbore requires financially demanding and time-consuming operations. In this study, a reservoir characterization model for tight-gas sand reservoirs is developed and tested. The model described is based on artificial neural networks trained with a large number of numerical-simulation scenarios of tight-gas sand reservoirs. The model is designed in an inverse-looking fashion to estimate the reservoir and hydraulic-fracture characteristics, once known initial conditions, controllable operational parameters, and observed horizontal-well performance are input. Validation with blind cases by estimating reservoir and hydraulic-fracture characteristics resulted in an average absolute error of 20%. The model was also tested successfully with published data of an average-performing well in the Granite Wash Reservoir. A graphical-user-interface application that enables using the model in a practical and efficient manner is developed. Practicality of the model is also demonstrated with a case study for the Williams Fork Formation by obtaining probabilistic estimates of reservoir/hydraulic-fracture characteristics through Monte Carlo simulation that incorporates the ranges of observed production performance.

Development of a data-driven forecasting tool for hydraulically fractured, horizontal wells in tight-gas sands

Tight-gas sand reservoirs are considered to be one of the major unconventional resources. Due to the strong heterogeneity and very low permeability of the formation, and the complexity of well trajectories with multiple hydraulic fractures; there are challenges associated with performance forecasting and optimum exploitation of these resources using conventional modeling approaches. In this study, it is aimed to develop a data-driven forecasting tool for tight-gas sands, which are based on artificial neural networks that can complement the physics-driven modeling approach, namely numerical-simulation models. The tool is designed to predict the horizontal-well performance as a proxy to the numerical model, once the initial conditions, operational parameters, reservoir/hydraulic-fracture characteristics are provided. The data-driven model, that the forecasting tool is based on, is validated with blind cases by estimating the cumulative gas production after 10 years with an average error of 3.2%. A graphical-user-interface application is developed that allows the practicing engineer to use the developed tool in a practical manner by visualizing estimated performance for a given reservoir within a fraction of a second. Practicality of the tool is demonstrated with a case study for the Williams Fork Formation by assessing the performance of various well designs and by incorporating known uncertainties through Monte Carlo simulation. P10, P50 and P90 estimates of the horizontal-well performance are quickly obtained within acceptable accuracy levels.

Understanding the Roles of Inflow-Control Devices in Optimizing Horizontal-Well Performance

Summary An inflow-control device (ICD) is completion hardware that is deployed as part of well completions aimed at distributing the inflow evenly. Even though the detailed structures vary from one design to another, the principle for different ICDs is the same—restrict flow by creating additional pressure drop and therefore adjusting wellbore pressure distribution to achieve an evenly distributed flow profile along a horizontal well. With a more evenly distributed flow profile, one can reduce water or gas coning, prevent sand production, and solve other drawdown-related production problems. In general, ICDs are not adjustable; once installed in the well, the location of the device and the relationship between rate and pressure drop are fixed. This makes the design of a well completion and ICDs extremely critical for production. ICDs can be either beneficial or detrimental to production, depending on the reservoir condition, well structure, and completion design. Realizing that reservoir conditions will change during the life of a well, the impact of an ICD is a function of time. Reservoir heterogeneity and uncertainty can complicate the situation easily. The ICDs sometimes can be overlooked if the design is based only on reservoir flow simulations at initial conditions. In this paper, we will investigate how and when an ICD should be used. An integrated analysis method of inflow (reservoir) and outflow (wellbore) is used to generate the flow profile of a horizontal well, and additional frictional pressure drop created by ICDs will be considered. Two conditions that result in production problems, wellbore pressure drop and reservoir heterogeneity, will be addressed. The focus will be on when and how an ICD can optimize production. Examples will be used to illustrate that it is critical to understand the reservoir conditions and wellbore dynamics together when designing a well completion with ICDs. The observations from this study show that overdesigned ICDs will not just increase the cost of well completion, but also will impact the well performance negatively. ICDs are not a universal solution of production problems. The application requires a thorough understanding of long-term reservoir behavior and upfront reservoir characterization for implementation.

Overview: Completions Today (September 2006)

The clear objective for any well is that it should perform to the full potential of the formation it penetrates and remain stable throughout its lifetime. This goal is best achieved by avoiding formation damage in the first place, but in most cases this is not possible. In reality, all reservoirs are damaged to some extent by drilling/completion fluids. The important issue is whether this damage affects well productivity significantly. Optimum completion design is essential in maximizing the value available from the reservoir. Poorly planned or executed completion strategies can easily reduce production (and revenue) streams by up to 50%. While there appears to be a consensus on the mechanism of formation damage, there is growing divergence over how it may be combated or avoided. Recent research indicates that fluctuations in wellbore pressure during the first milliseconds after perforation-gun firing govern the perforating-tunnel cleanup, rather than the initial static underbalance as originally thought. A completion design in which perforating bypasses invasion combined with a new design that ensures dynamic underbalance at all times has yielded very good results. Intelligent-completion technologies provide downhole sensing and communication and remote control of completion tools. This technology allows operators on the surface and in remote locations to optimize reservoir performance by interpreting downhole data in real time, then operating flow-control devices accordingly. To get a broader uptake of intelligent-completion technologies, there is a need for compelling success stories documenting the value of new and existing technology. Sharing these experiences could increase opportunities for broader implementation among operators of both conventional and unconventional reservoirs. With the current oil and gas revenues, many opportunities exist for major operators to spend more capital on intelligent-completion technologies; a 10 to 20% increase in hydrocarbon recovery can balance the risks and opportunities of investing in challenging projects and the capabilities to bring them to fruition. The willingness to share success stories as well as failures when documenting new technology is an important factor in achieving faster deployment of advanced completion technologies. As this concept becomes a reality in more fields, the upstream petroleum industry will enjoy increased efficiency and ultimate hydrocarbon recovery at lower cost. Considering that completion takes a substantial stake in the total capital expenditure for a new well, the cost and effect of the well completion is too significant to be ignored. Completions Today additional reading available at the SPE eLibrary: www.spe.org SPE 97175 "External Casing Perforating Provides Optimal Treatment Coverage in Horizontal Pay" by J.L. Rodgerson, BJ Services Co., et al. SPE 99691 "First Through-Tubing Gravel-Pack Recompletion Performed in Japan" by M. Numasawa, Japan Petroleum Exploration Co. Ltd., et al. SPE 100413 "Efficient Cost Saving Through an Appropriate Completion Design" by L.-B. Ouyang, Chevron Energy Technology Co., et al. SPE 96395 "Numerical Investigation of Horizontal-Well Performance With Selective Completion" by R. Kalita, Schlumberger, et al.

Productivity of Selectively Perforated Horizontal Wells

Summary This paper investigates the effect of selective perforating on horizontal-well performance. Theoretical investigation is based on a general 3D analytical model that was published previously. For a given perforation design, the changes in flow rate, pseudosteady-state productivity, and cumulative production can be computed using the solution. The investigation shows that the ratio of total-perforated length to the drilled-well length is the most dominant parameter controlling the long-term performance of the selectively perforated horizontal wells. The other important parameters are the degree of formation and perforating damage. We additionally examined the effect of the so-called "oriented perforating" on the horizontal-well performance in isotropic and anisotropic formations. Our research shows that accurately oriented perforating could significantly improve the well productivity in anisotropic formations.

Productivity of Horizontal Wells Completed With Screens

SummaryAn integrated flow model is developed to simulate the flow into horizontal wells with screens. The model is composed of a multisegment horizontal-well model and a near-wellbore model. The multisegment horizontal-well model predicts the pressure losses in a bounded reservoir. The near-wellbore model simulates the fluid flow through the damaged/collapsed zone around the wellbore, the mudcake, the wellbore/screen interface, the gravel-packed annulus, and the screen itself.Using the model, we investigated the effects of degree of screen damage, nonuniform damage removal, mudcake properties, and blank-pipe insertion on horizontal-well productivity. We examined and compared the long-term horizontal-well performance in terms of rate decline and cumulative production as a function of time.

Inflow Performance Relationship for Perforated Horizontal Wells

SummaryThis paper presents an investigation of perforated horizontal-well performance in areally anisotropic reservoirs. Theoretical investigation is based on a 3D analytical IPR model. The analytical IPR model considers an arbitrary distribution of perforations along the completed segments. Changes in flow rate, pseudosteady-state productivity, and cumulative production can be computed using the solution.The analytical IPR model was compared with the models available in the literature and verified. It was then used to investigate the effects of well and reservoir parameters on the inflow performance of perforated horizontal wells.

Discussion and Comparison of Horizontal-Well Performance in Bouri Field

Summary Seven horizontal wells were drilled in Bouri field, offshore Libya, and put on production between 1989 and 1992. This paper presents the experience gained in producing and monitoring these wells over the past few years. Comparison of well basic characteristics and performances with offset conventional wells indicates their higher productivity and general superior performance. Different monitoring activities conducted on these wells are discussed, including transient test analyses and production logs. Free gas production was found to be related to the combined phenomena of coning and fracture flow mechanism. These discussions show that, in most of the cases, production of water and gas is inevitable as long as economic oil rates are to be maintained. The targets set for these wells in terms of recovery increase and production troubles reduction were at least partially fulfilled.

Effects of Grid Systems on Predicting Horizontal-Well Productivity

Summary We compare horizontal-well performance for different grid types using a conventional formula for the well index. These results are also compared with the results of explicit well modeling, which does not require a well index. To assess the accuracy of numerical solutions, examples chosen are those for which exact analytical solutions are also available. These analytical solutions are for horizontal wells in brick-shaped homogeneous (isotropic or aniso-tropic) reservoirs (or drainage volumes). When a horizontal well extends through the full length of the reservoir, the problem be-comes two-dimensional with uniform influx along the well. On the other hand, if the well is completed in only a part of the reservoir (partially penetrating) a three-dimensional (3D) solution is needed. The 3D solution also predicts the influx profile along the well, with higher influx at the two ends. Because the conventional well index calculation does not account for the 3D nature of flow, the flow rate of the well may be incorrect. We have found that the well index obtained with the default procedure in most simulators (Peaceman's method) needs to be increased for the numerical simulator to predict the productivity of horizontal wells correctly. The correct well index can be obtained for any well if a suitable analytical solution is available. When such solutions are not avail-able, reference solutions can also be obtained by explicitly mod-eling the well with blocks that are of the same size as the well. In this case, there is no need for a well index. However, our analysis shows that for correct results the grid-aspect ratio for blocks rep-resenting the well and surrounding blocks has to be close to 1.

Application of Short-Radius Horizontal Boreholes in the Naturally Fractured Yates Field

Summary This paper discusses the performance and simulation of short-radius horizontal boreholes being used in the Marathon-operated Yates Field Unit in west Texas to minimize drawdown and therefore to reduce gas and water coning in a thin oil column. Yates is a very prolific field with extensive fracturing and high-quality reservoir rock. Superimposed on a high-density orthogonal fracture network are widely spaced regional joints with a strong directional tendency. Major questions are how these directional joints affect the horizontal-well performance and whether wells should be drilled parallel or perpendicular to the joints. Dual-permeability reservoir simulation studies were performed to study optimum orientation of the borehole with respect to the natural fracture network. Additionally, optimum well-completion elevation was studied. Forty-six vertical wells have been recompleted as short-radius horizontal boreholes since 1986. The large productivity increase of the horizontal boreholes compared with the previous vertical completions indicates that the wells are intersecting the regional joints.

Application of Open-Architecture Computing Environment in Reservoir Simulation

Summary Open architecture has reshaped the computer marketplace and has significantly affected the development, maintenance, and application of reservoir simulation technology. We have moved rapidly from mainframe computers to distributed applications on workstations. Here, we discuss four open-systems initiatives (communication, language, operating system, and graphics) that have particularly influenced reservoir simulation at Mobil R and D Corp. Over the last 2 decades, our simulators have grown from 50,000-line single-well programs to greater than 1.5-million lines of code in the current field simulator. Advances in open systems have enabled us to manage this explosive growth on a network of workstations. We have been able to standardize around the UNIX operating system and C and FORTRAN languages. X-Window MOTIF-based interactive graphics have been a key element in migrating the simulator to a variety of computers. Although these open-architecture initiatives have had a significant and positive impact on reservoir simulation at Mobil, we still are faced with certain disadvantages. This paper discusses how we overcame these disadvantages and the challenges we face in the future. Introduction "Open systems" has become one of the most overused computer buzz words, yet that concept is credited with reshaping the marketplace. This paper describes four open initiatives as interpreted at Mobil and presents a metric to quantify their impact on the development, maintenance, and application of the company's reservoir simulators. For the purposes of this paper, a reservoir simulator is simply a computer program whose heart is a computationally intensive numerical model. The program processes the physical description of the reservoir (e.g., the type of fluid, pressure, saturation, temperature, and geology). It also processes the proposed development strategy in the form of operating constraints. Using this information, it predicts the effectiveness of different production strategies and is used to optimize gas and oil recovery from petroleum reservoirs. During the last 2 decades, Mobil has developed four reservoir simulators. Fig. 1 shows that the number of lines of code in each program increased dramatically as more complex engineering features were incorporated. The first of these programs, WELCOS, was released more than 20 years ago. That black-oil simulator could model the behavior of only a single well and was used extensively for water- and gas-coning studies. Written in FORTRAN, it consisted of less than 50,000 statements. By 1975, Mobil had developed ALPURS. It was also a black-oil model, but ALPURS had the power to model all the wells in a field. ALPURS contained sophisticated well controls that enabled it to model complex production strategies. ALPURS also provided limited, black-and-white plotting and contouring capabilities. Because of its added engineering capabilities, ALPURS was six times the size of WELCOS, or about 300,000 lines. In the mid-1980's, Mobil developed a fullfield, compositional reservoir model, COSMOS. It was about one-third larger than ALPURS, with more than 400,000 statements. PEGASUS is a multipurpose, compositional, black-oil simulator capable of modeling a broad range of reservoirs with complex geology and fluid behavior, each with different production strategies. It integrates various modeling capabilities, such as a sophisticated well-management scheme for full-field studies and accurate predictions of horizontal-well performance. PEGASUS is used to study gas-condensate, volatile-oil, faulted, and fractured reservoirs. It also has gas-storage applications. It is 30 times the size of WELCOS and contains more than 1,500,000 statements. The interactive color graphics feature for interpretation of simulation results represents about 40% of the code.

Comprehensive simulation of horizontal-well performance : Economides, M J; Deimbacher, F X; Brand, C W; SPE Form Eval V6, N4, Dec 1991, P418–426

Comprehensive simulation of horizontal-well performance : Economides, M J; Deimbacher, F X; Brand, C W; SPE Form Eval V6, N4, Dec 1991, P418–426