Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Permian Basin
Abstract This paper presents the methodology and results of a reservoir characterization study of Clear Fork carbonates in the TXL South Unit Field located in Ector County, Texas. The principal objective of our study was to evaluate a targeted infill drilling strategy for future field development. Our study incorporated an integrated approach for which the primary evaluation tool was decline type curve analysis of well production data. The well performance analysis was both supplemented and complemented with petrophysical and geological studies, each representing different reservoir scales. On the basis of our study, we identified areas of the field with the highest reservoir quality and largest oil-in-place volume, thus identifying the areas of the field best suited for infill drilling. Introduction Like most Permian-age carbonate reservoirs in the Permian Basin, Clear Fork carbonates in the TXL South Unit Field are characterized by very thick, heterogeneous pay intervals with significant discontinuities, both laterally and vertically. Low reservoir energies, consistent with solution-gas-drive oil reservoirs, as well as low effective permeabilities to oil are manifested by primary production recovery efficiencies typically ranging from 8 to 12 percent on 40-acre well spacing. Consequently, infill drilling is required not only to increase recoveries from primary production, but also to enhance sweep efficiencies and improve recovery from secondary and tertiary enhanced oil recovery operations. Even at reduced well spacing, however, many operators observe low oil recoveries, poor sweep efficiencies, and early water breakthrough. Poor performance at a denser well spacing is indicative of the significant reservoir discontinuity. Accordingly, a better understanding of the reservoir heterogeneity will help to design and implement enhanced oil recovery operations more successfully. Moreover, operators in the Permian Basin have historically implemented "blanket" infill drilling strategies in which wells are drilled on uniform patterns and spacing with little consideration of reservoir quality. Development at non-optimum well spacing may result in poor economic returns, even under favorable oil pricing scenarios similar to current conditions. In fact, several previous studies have shown that "targeted" infill drilling programs are required to optimize field development by reducing capital expenditures and maximizing economic returns. Targeted infill drilling, however, requires a reservoir characterization program to identify areas of the field with the best quality rock and the largest volume of oil-in-place. Because of the significant volume of original oil-in-place remaining in Permian-age carbonates in West Texas, there is an economic incentive for optimizing field development with infill drilling programs, both for primary depletion and enhanced oil recovery operations. The purpose of this paper is to present the methodology and results of a reservoir characterization study of the Clear Fork carbonates in the TXL South Unit Field located in Ector County, Texas. Similar to a study conducted by Doublet, et al. for the North Robertson Unit in Gaines County, we incorporated an integrated approach in which we combined results from geological, petrophysical, and reservoir performance analyses, each representing different reservoir scales. Furthermore, rather than initiating a cost-prohibitive data acquisition program, we conducted our study using existing field data typically available to most operators. Historical Field Background Located in the center of the Central Basin Platform in the Permian Basin, the TXL South Unit encompasses approximately 10,200 acres in the western half of Ector County, Texas. Wells in the TXL South Unit produce from both the Upper Clear Fork (5600 Reservoir) and the Lower Clear Fork (Tubb Reservoir). As shown by Figure 1, current field production is about 1,000 STB/day and 3,000 Mscf/day from approximately 400 active wells.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.96)
- Geology > Sedimentary Geology (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (31 more...)
Abstract This work provides the development, validation, and appli-cation of new decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir. This work fills a significant void in the modern inventory of decline type curves. In particular, this work is directly applicable to production data analysis for cases taken from low permeability gas reservoirs. Using an appropriate analytical solution for this case, we pre-pared "decline" type curves for FcD values from 0.1 to 1000 - individual type curves are generated for each FcD value using a range of reD values from 2 to 1000. The following "type curves" are provided:"Fetkovich" format rate-time decline type curves (con-stant pressure case): qDd versus tDd "Fetkovich-McCray" format rate-time decline type curves (equivalent constant rate case): qDd versus "Fetkovich-McCray" format rate-cumulative decline type curves: qDd versus NpDd We provide an example demonstration of the methodology for decline type curve analysis using a field case of continuously measured production rate and surface pressure data obtained from a low permeability gas reservoir. These solutions/type curves provide an analysis/interpretation mechanism that has not previously been available in the petroleum literature. Compared to field data, we find that the traditional type curve solutions for an infinite conductivity vertical fracture are typically inadequate - and, the new solutions for a well with a finite conductivity vertical fracture clearly show much more representative behavior. This validation suggests that the proposed type curves will have broad utility in the petroleum literature - particularly for applications in low permeability gas reservoirs. Objectives The following objectives are proposed for this work:To develop and validate a series of decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir. To provide a methodology for using decline type curves to analyze and interpret production or injection well performance for a well with a finite conductivity vertical fracture. To demonstrate these new type curves using continuously measured production data (rates and pressures). In considering these objectives we note that we are strongly motivated to provide these tools in light of the current high level of activity in the analysis and interpretation of reservoir performance data acquired from low permeability gas reservoirs. We recognize that current methods based on the case of a vertical well with an infinite conductivity vertical fracture are overly-ideal for low permeability reservoirs and we must reconcile the need for a new decline type curve for a finite conductivity vertical fracture. This rationale is the moti-vation for this work.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Summary In this paper we present a rigorous theoretical development of solutions for boundary-dominated gas flow during reservoir depletion. These solutions were derived by directly coupling the stabilized flow equation with the gas material balance equation. Due to the highly nonlinear nature of the gas flow equation, pseudo pressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudo pressure and pseudotime functions do provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history, which in most cases is simply not available. Our approach uses functional models to represent the viscosity-compressibility product as a function of the reservoir pressure/z-factor (p/z) profile. These models provide approximate, but direct, solutions for modeling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as the prediction of rate or cumulative production. We also provide verification of our new flow rate and pressure solutions using the results of numerical simulation and we demonstrate the application of these solutions using a field example. Introduction We focus here on the development and application of semi-analytic solutions for modeling gas well performance¾with particular emphasis on production rate analysis using decline type curves. Our emphasis on decline curve analysis arises both from its usefulness in viewing the entire well history, as well as its familiarity in the industry as a straightforward and consistent analysis approach. More importantly, the approach does not specifically require reservoir pressure data (although pressure data are certainly useful). Decline curve analysis typically involves a plot of production rate, qg and/or other rate functions (e.g., cumulative production, rate integral, rate integral derivative, etc.) vs. time (or a time-like function) on a log-log scale. This plot is matched against a theoretical model, either analytically as a functional form or graphically in the form of type curves. From this analysis formation properties are estimated. Production forecasts can then be made by extrapolation of the matched data trends. The specific formation parameters that can be obtained from decline curve analysis are original gas in place (OGIP), permeability or flow capacity, and the type and strength of the reservoir drive mechanism. In addition, we can establish the future performance of individual wells, and the estimated ultimate recovery (EUR). Attempts to theoretically model the production rate performance of gas and oil wells date as far back as the early part of this century. In 1921, a detailed summary of the most important developments in this area was documented in the Manual for the Oil and Gas Industry.1 Several efforts2,3 were made over the years immediately thereafter, and probably the most significant contribution towards the development of the modern decline curve analysis concept is the classic paper by Arps,2 written in 1944. In this work Arps presented a set of exponential and hyperbolic equations for production rate analysis. Although the basis of Arps' development was statistical (and therefore empirical), these historic results have found widespread appeal in the oil and gas industry. The continuous use of the so-called "Arps equations" is primarily due to the explicit form of the relations, which makes these equations quite useful for practical applications. The next major development in production decline analysis technology occurred in 1980, when Fetkovich4 presented a unified type curve which combined the Arps empirical equations with the analytical rate solutions for bounded reservoir systems.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- (2 more...)
Abstract This paper presents a rigorous theoretical development of long term boundary-dominated flow solutions which involve direct coupling of the stabilized flow equation with the gas material balance equation. Due to the highly non-linear nature of the gas flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history - which in most cases is simply not available. Our approach uses functional models to relate the viscosity-compressibility product with the reservoir pressure (p/z) profile. These models provide approximate, but direct, solutions for modelling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as rate prediction. We also provide verification of our new flowrate and pressure solutions using numerical simulation results and we demonstrate the application of these solutions using a field example. Introduction This paper focuses on the development and application of semianalytic solutions for modelling gas well performance - with particular emphasis on production rate analysis using decline type curves. Our emphasis on decline curve analysis arises both from its utility in viewing the entire well history, as well as its familiarity in the industry as a straightforward and consistent analysis approach. More importantly, the approach does not specifically require reservoir pressure data (although pressure data are certainly useful). Decline curve analysis typically involves a plot of production rate, qg and/or other rate functions (e.g., cumulative production, rate integral, rate integral-derivative, etc.) versus time on a log-log scale. This plot is matched against a theoretical model, either analytically as a functional form, or graphically in the form of type curves. From this analysis formation properties are estimated. Production forecasts can then be made by extrapolation of the matched data trends. The specific formation parameters that can be obtained from decline curve analysis are–Original-gas-in-place (OGIP), –Permeability or flow capacity, and –The type and strength of the reservoir drive mechanism. In addition, we can establish–The future performance of individual wells, and –The estimated ultimate recovery (EUR). Attempts to theoretically model the production rate performance of gas and oil wells date as far back as the early part of this century. In 1921, a detailed summary of the most important developments in this area was documented in the Manual for the Oil and Gas Industry. Several efforts were made over the years immediately thereafter, and probably the most significant contribution towards the development of the modern decline curve analysis concept is the classic paper by Arps, written in 1944. In this work Arps presented a set of exponential and hyperbolic equations for production rate analysis. Although the basis of Arps' development was statistical, and therefore empirical, these historic results have found widespread appeal in the oil and gas industry. The continuous use of these so-called "Arps equations" is primarily due to the explicit form of the relations, which makes them easy for practical applications.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- (2 more...)
SPE 35161 Pressure Transient Data Acquisition and Analysis Using Real Time Electromagnetic Telemetry L.E. Doublet,* Texas A&M U., J.W. Nevans,* Fina Oil & Chemical Company, M.K. Fisher,* ProTechnics Company, R.L. Heine,* Real Time Diagnostics, Inc., and T.A. Blasingame,* Texas A&M U. *SPE Members Copyright 1996, Society of Petroleum Engineers, Inc. Abstract This paper presents the operational procedures and the results for two pressure buildup tests performed using a wireless telemetry acquisition system (TAS) tool at the North Robertson (Clearfork) Unit (NRU) in Gaines, Co. Tx. Using a single pressure gauge system downhole we obtained real-time telemetry of pressure and temperature data at the surface, as well as a larger sampling of data that were stored in the downhole memory system. This new wireless telemetry acquisition system was developed to provide real-time pressure and temperature data at the surface by using an electromagnetic signal to transmit these data through the formation strata. The tool is fully programmable so that a wide range of sampling frequencies can be used. The system allows pressure and temperature data to be stored downhole (as in the case of a typical "memory" gauge), or these data can be transmitted to surface data acquisition systems. This provides real-time pressure and temperature data for pressure transient tests, stimulation monitoring. and long-term reservoir surveillance. Our objective is to demonstrate the use of this technology for pressure buildup tests in low permeability reservoirs. Our goal in utilizing this technology is to reduce the shut-in time requirements for pressure transient tests - which will ultimately result in a more cost-effective reservoir surveillance program as wells can be returned to production (or injection) as quickly as possible. Once the pressure data were acquired, we performed conventional semilog and log-log analysis, and we simulated test profiles to verify the analyses of the test data. Both surface and downhole pressure data were compared for consistency, and both types of data were analyzed in exactly the same fashion. The results of these analyses were essentially identical. This approach gave consistent estimates of reservoir pressure, permeability, skin factor, and fracture half-length for both of our case histories. Introduction The accurate acquisition and analysis of pressure transient data is an integral part of the reservoir surveillance process. By analyzing the characteristic shape of the pressure-time profile we can determine the reservoir-well model (i.e., homogeneous or dual-porosity reservoir conditions, hydraulically-fractured or horizontal well behavior, wellbore storage conditions, etc.). Specifically, we can use pressure transient data to estimate the following:–average reservoir pressure, –completion efficiency, –reservoir quality, –well drainage radius and reservoir shape, and –flow boundaries or other reservoir heterogeneities. Unfortunately, in the majority of operating environments the critical issue for most pressure transient tests is the timely return of a well to production or injection. This paper presents one methodology that shows promise in minimizing test time while fulfilling the data acquisition requirements. When performing pressure transient tests in the low permeability reservoirs of the Permian Basin (such as the NRU), it has been our experience that a test of at least two to three weeks is required for a comprehensive analysis to be possible. The issue is that the low permeability character of these reservoirs, combined with often severe wellbore storage effects, distorts test data and conventional analysis techniques cannot be used until these effects end. One remedy is a downhole shut-in device. but this device can be difficult to install, it requires considerable well preparation, and is quite expensive. Our approach was to minimize the test time by using real-time data for analysis. Conceptually, we can monitor the test and terminate once a valid analysis is obtained - but in our cases we continued data acquisition until the power source in the tool depleted. We did this for two reasons - first, we wanted to acquire as much data as possible; and second, we wanted to establish the practical operating limits of this data acquisition system. To estimate well drainage radius and identify flow boundaries we have found from pressure falloff tests that a total test duration of between five and eight weeks is required. Obviously, it is not economically feasible to shut-in producing wells for this period of time. In the future we may use the TAS tool for long-term surveillance tests, but at present this task is neither operationally nor economically feasible. P. 149
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.66)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
An Integrated Geologic and Engineering Reservoir Characterization of the North Robertson (Clearfork) Unit: A Case Study, Part 1
Doublet, L.E. (Texas A&M U.) | Pande, P.K. (Fina Oil and Chemical Company) | Clark, M.B (Fina Oil and Chemical Company) | Nevans, J.W. (Fina Oil and Chemical Company) | Blasingame, T.A. (Texas A&M U.)
BRIEF SUMMARY Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability carbonate reservoirs. These reservoirs are typically characterized by:–Large, discontinuous pay intervals –Vertical and lateral changes in reservoir properties –Low reservoir energy –High residual oil saturation –Low recovery efficiency The operational problems we encounter in these types of reservoirs include:–Poor or inadequate completions and stimulations –Early water breakthrough –Poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the near-well regions –Channeling of injected fluids due to preferential fracturing caused by excessive injection rates –Limited data availability and poor data quality Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geologic, petrophysical, reservoir performance, and pressure transient analyses, then this "integrated" approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to "blanket" infill drilling methods. New and emerging technologies such as cross-borehole tomography, geostatistical modeling, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can be used to develop a 3-D simulation model for prediction of infill locations. In this work, we will demonstrate the application of reservoir surveillance techniques to identify additional reservoir pay zones, and to monitor pressure and preferential fluid movement in the reservoir. These techniques are: long-term production and injection data analysis, pressure transient analysis, and advanced open and cased hole well log analysis. The major contribution of this paper is our summary of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit. Introduction There are many complicated factors that will affect the successful implementation of infill drilling programs in heterogeneous, low permeability carbonate reservoirs such as the Clearfork/Glorieta of west Texas. Before we began this project, we conducted an extensive literature review to gain a better understanding of the producibility problems we face at the North Robertson Unit (NRU). Fortunately, these reservoirs have a long producing history and there is a large quantity of useful data available from case studies for primary, secondary, and tertiary operations in the Clearfork and other analogous reservoirs. In a 1974 case study concerning waterflooding operations at the Denver (San Andres) Unit, Ghauri, et al gave valuable insights concerning reservoir discontinuity, injector-producer conformance, and the effect of reservoir quality on reservoir sweep efficiency. Poor reservoir rock quality and the existence of discontinuous pay between injection and producing wells resulted in a recommendation to reduce nominal well spacing from 40 acres to 20 acres. An outcrop study on the San Andres was performed to verify reservoir discontinuity. Injection wells were completed and stimulated preferentially in an effort to flood only the continuous layers of the reservoir. The original peripheral injection design was converted to inverted nine-spot patterns in an effort to decrease the amount of water channeling and early water breakthrough via the most permeable members. P. 465
- Overview (1.00)
- Research Report > New Finding (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Tidal Flat Environment (0.68)
- Geology > Mineral (0.67)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.93)
- Geophysics > Seismic Surveying > Seismic Modeling (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.45)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (4 more...)
- Information Technology > Modeling & Simulation (0.87)
- Information Technology > Data Science > Data Quality (0.34)
Abstract This paper presents rigorous methods to analyze and interpret production rate and pressure data from oil wells using type curves to perform decline curve analysis. These methods are shown to yield excellent results for both the variable rate and variable bottomhole pressure cases, without regard to the structure of the reservoir (shape and size), or the reservoir drive mechanisms. Results of these analyses include the following:Reservoir properties: Skin factor for near well damage or stimulation, s Formation permeability, k In-place fluid volumes: Original oil-in-place, N Movable oil at current conditions, Np, mov Reservoir drainage area, A We have thoroughly verified these analyses and interpretation methods using both synthetic data and numerous field examples. In addition, we provide illustrative examples to demonstrate the ease of analysis and interpretation, as well as to orient the reader as to what are the benefits of rigorous decline curve analysis. Introduction The importance of performing accurate analysis and interpretation of reservoir behavior using only rate and pressure data as a function of time simply can not be overemphasized. In most cases, these will be the only data available in any significant quantity, especially for older wells and marginally economic wells where both the quantity and quality of any types of data are limited. The theoretical application of this technique is for newer wells, at pressures above the bubble point, although we show that the methods described here can be accurately applied at any time during the depletion history of a particular well. The development of modem decline curve analysis began in 1944 when Arps published a comprehensive review of previous efforts for the graphical analysis of production decline behavior. In that work, Arps developed a family of functional relations based on the hyperbolic decline model for the analysis of flow rate data. Arps' efforts provided a variety of results; including the exponential, hyperbolic. and harmonic rate decline relations that we use today for empirical decline curve analysis. Due to the simplicity and consistency of this empirical approach, the Arps relations remain a benchmark in the industry for the analysis and interpretation of production data. The utility of the Arps relations is the applicability of the hyperbolic family of curves to model a wide variety of production characteristics. In addition, the simplified analysis of exponential and hyperbolic data trends (such as the graphical techniques provided by Nind) maintain the popularity of the Arps relations. The application of the Arps relations typically includes a semilog plot of rate versus time where the hyperbolic cases yield gently declining curves which have the straight-line, exponential decline case as a lower limit. Nind provides the development and illustration of plotting functions for the graphical analysis of rate data for the general hyperbolic decline case as well as the exponential decline case. Another attraction of the Arps relations is their use in graphical as well as functional extrapolation. Many analysts rely uniquely on the Arps relations for performance predictions. often without realizing the empirical nature of such extrapolations. In this work we will use exponential decline case as a basis for estimating movable oil at current conditions, Np, mov. We will demonstrate that this approach can be derived theoretically for the case of a well produced at a constant bottomhole flowing pressure. We will also show that this approach works for wells which are not produced at such restrictive conditions.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
Summary Data acquisition design and implementation challenges for mature reservoirs which are targets for Improved Oil Recovery (IOR) applications are discussed in this paper. Examples are provided for Shallow Shelf Carbonate (SSC) reservoirs in the Permian Basin of West Texas. What Are Mature reservoirs? Mature reservoirs are defined as properties with additional recovery potential by implementation of advanced reservoir characterization tools and techniques, reservoir management and/or changes in recovery mechanisms. Attributes of mature reservoirs are depicted in Figure 1, which shows the importance of reservoir characterization as a function of field development stage. Reservoir characterization and an understanding of heterogeneity become more important for maturing reservoirs as these factors have a profound impact on future reservoir development and management strategies. Mature reservoirs are typically characterized by some type of secondary drive mechanism. A change to a tertiary mode or implementation of other lOR methods may be necessary to extend the economic limit and productive life of the field. A team approach is also important to achieve data acquisition objectives in mature reservoirs. However, the data acquisition situation may be very different from that "new" reservoirs. The desire and need for IOR may be critical as the economic limit may be rapidly approaching and data required for IOR may not be available. Smaller reservoir size and lower remaining reserves may present economic constraints towards the acquisition of essential data for the implementation of many IOR methods. The lack of production, fluid properties and other data in the earlier stages of field development may present uncertainties in history matching with numerical simulation methods. This results in unreliable reservoir performance forecasts for IOR. Often, the implementation of data acquisition programs in mature reservoirs present opportunities to enhance near-term reservoir performance through effective reservoIr management. Data acquisition strategies for properties which are being considered for abandonment are not addressed in this paper. Redevelopment of these properties is often required to exploit behind pipe potential and undeveloped zones or horizons. INTRODUCTION - DATA ACQUISITION METHODOLOGY The data acquisition process for mature reservoirs can be segmented into two major areas:
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Application of Integrated Reservoir Management and Reservoir Characterization To Optimize Infill Drilling
Pande, P.K. (Fina Oil & Chemical Co.) | Clark, M.B. (Fina Oil & Chemical Co.) | Blasingame, T.A. (Texas A&M U.) | Kelkar, Mohan (U. of Tulsa) | Vessell, R.K. (Mobil E&P U.S. Inc.) | Hunt, P.E. (Mobil E&P U.S. Inc.)
Abstract This project demonstrates the application of Advanced Secondary Recovery (ASR) technologies to remedy producibility problems at the North Robertson (Clearfork) Unit, in Gaines County, Texas. The North Robertson (Clearfork) Unit is a Shallow Shelf Carbonate (SSC) reservoir of Permian-Leonardian age operated by Fina Oil and Chemical Company. The Department of Energy (DOE) has selected the Unit as a Mid-Term Field Demonstration under the DOE Class II Oil Program. Producibility Problems Important producibility problems exhibited at the North Robertson (Clearfork) Unit include:Poor sweep efficiency due to a large, low permeability reservoir interval that is heterogeneous and compartmentalized, which results in poor vertical and lateral continuity of reservoir flow units. Poor balancing of injection and production rates in certain areas of the reservoir which indicates poor pressure and fluid communication and limited repressuring—possibly remedied by improved injection and production scheduling as well as injection and production well pattern re-alignments. Both injection and production wells are not optimally completed with regard to placement of perforations and the stimulation treatment is inadequate for optimal production and injection practices. Reservoir Management Study Areas To characterize the reservoir in terms of petrophysical properties and well deliverabilities (production potential), three different areas for focused study at the North Robertson Unit have been identified. These areas are known as Pre-Demonstration Reservoir Management Study Areas or PDSAs and were established based on varying performances of historical oil production, from excellent to poor. These areas will serve as intense areas of study, with testing optimization, simulation and forecasting, and surveillance activities during the project. Advanced Recovery Technologies The Advanced Secondary Recovery technologies to be demonstrated at the North Robertson (Clearfork) Unit include:Development of an integrated reservoir description created using reservoir characterization and reservoir management activities—and integration and modelling of the data from these activities using geostatistical interpretations (realizations), 3-dimensional reservoir simulation, and analytical solution methods. Acquisition and analysis of geological data: core and well log data. P. 899^
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.30)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
This is a preprint — subject to correction. Abstract The motivation for the work described in this paper arose front a need to analyze production decline data where the flowing bottomhole pressure varies significantly. The variance of the Bottomhole pressure with time excludes the use of the exponential decline model for conventional decline curve analysis (semilog plots and type curves), Using pressure normalized flow rate plots and type curves), Using pressure normalized flow rate rather than flow rate usually does not remedy this problem. The method we present uses a rigorous superposition function to account for the variance of rate and pressure during production. This function is the constant rate analog for variable-rate flow during post-transient conditions and can be used to develop a constant pressure analog for the decline curve analysis of field data. The constant pressure analog time function is computed from the constant rate function using the identity that cumulative production for both cases must be equal. Using the cumulative production for both cases must be equal. Using the cumulative production identity, we solve recursively for the time function production identity, we solve recursively for the time function using trapezoidal rule integration and, as an alternative, finite difference formulae, We have also developed a constant pressure analog time relation which is rigorous for boundary dominated flow and serves as an accurate approximation for transient flow. We apply these relations to analytical solutions for verification and then use the boundary dominated flow relation on simulated and field cases. These simulation cases include large and small step changes in bottomhole flowing pressures, and periodic shut-ins. Finally, we apply these relations to a gas well field case. Introduction The widespread use of type curves 1-3 to analyze rate decline data has motivated us to consider the implications of varying rate and pressure drop production. Theoretically speaking, for the flow of a slightly compressible liquid, the analytical stems on the Fetkovich type curve are valid only for the constant wellbore pressure production case. In previous works we have pressure production case. In previous works we have shown that variable-rate/variable pressure drop data may be transformed into an equivalent constant rate case for both gas and liquid flow data. Camacho independently verified that this equivalent constant rate formulation is exact for the constant pressure production of a slightly compressible liquid during boundary production of a slightly compressible liquid during boundary dominated flow conditions. McCray sought to develop a method to transform variable-rate/variable pressure drop data into an equivalent constant pressure case. In doing this, McCray developed a recursion pressure case. In doing this, McCray developed a recursion formula to compute an equivalent time for constant wellbore pressure production, tcp, that could be used with pressure drop pressure production, tcp, that could be used with pressure drop normalized flowrate to perform decline curve analysis using type curves. Although the approach suggested by McCray was verified using simulation, we sought a rigorous foundation for the application of this result. As it turns out, a relatively simple proof can be shown for the application of the tcp function during boundary dominated flow conditions. This proof is given in Appendix A. In addition to the proof of McCray's result, we also provide methods to compute the constant pressure equivalent time, tcp, using recursion formulae in Appendix B. In Appendix C we provide relations which can be used to compute the constant provide relations which can be used to compute the constant pressure dimesionless rate solution given the constant rate pressure dimesionless rate solution given the constant rate dimensionless pressure solution. In the text we will prove that the computational methods we provide yield essentially exact results during boundary dominated flow and give very good performance during transient flow. VERIFICATION USING DIMENSIONLESS SOLUTIONS Our first goal is to establish that our new method actually transforms a variable-rate/variable pressure drop system into an equivalent constant pressure system. We begin with a proof of the validity of our solution by transforming a constant rate system into a constant pressure system. Because these solutions are frequently used in dimensionless format, we will perform this verification using dimensionless variables.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)