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Abstract Objectives/Scope Transient well test analysis has been used to assess well condition and obtain reservoir parameters for over seventy years. At a time when Machine Learning (ML) and Artificial Intelligence (AI) are coming-of-age and may eventually replace well test interpreters, it is worth taking stock of the progress made in well test analysis since the major initial publications of the early 1950โs. Methods, Procedures, Process Major improvements in well test analysis since the early 1950's have occurred approximately 13 to 19 years apart, driven by the availability of both new types of data and new mathematical tools. Using a computer-generated data set of pressure and rate, we illustrate the evolution of well test analysis over the years: straight line methods of the early 1950's; log-log pressure plots of the late 1960's and early 1970's; formulation of an integrated methodology in the early 1980s; introduction of pressure-derivative analysis in 1983; derivation of a stable deconvolution algorithm in the early 2000's; and its current, successful extension to multiple interfering wells. Results, Observations, Conclusions Over the last seventy years, well test analysis has moved from just estimating well performance to becoming a very powerful tool for reservoir characterization. Novel/Additive Information Although the development of commercial software has been a factor in making practicing engineers aware of these improvements, acceptance has been slow: deconvolution has been developed twenty years ago and has been included in commercial software for the last fifteen years, yet is still not used in routine well test analysis. In addition, interest in well test analysis seems to be fading, which is in sharp contrast with its popularity in 1970's, as measured by the attendance to the well test analysis sessions in the annual ATCE meetings. It is hoped that the new advances in ML and AI will reverse this trend and reinstate well test analysis as a major reservoir characterization tool.
Method for Drawdown Analysis of a Multi-Stage Hydraulically Fractured Horizontal Well That Penetrates an Unconventional Naturally Fractured Reservoir
Gutierrez Oseguera, Alejandra (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract This paper examines the pressure response of a horizontal well that penetrates an unconventional, naturally fractured reservoir. The response is quite surprising. The expectation of linear flow is shattered, and only radial flow is observed. The radial flow two parallel straight lines in a semilogarithmic crossplot of flow pressure vs. time are present but they are reversed, with the last straight line showing smaller pressures as compared with the extrapolated first straight line. Two different methods are used; the first one is a conventional approach for analyzing the first semilog straight line with a view to calculating flow capacity and permeability well as skin. The second approach involves a novel dual porosity model that permits calculating several fracture parameters of interest, and to the best of our knowledge has not been published previously in the petroleum engineering literature. In this paper, new equations with a semi-empirical component, are presented that allow matching the reversed real pressure drawdown data as well as the corresponding pressure derivatives. The new model shows that fluid flow is dominated initially by the fractures as in the case of dual porosity conventional models. In the conventional model, flow pressure data deviate from the first straight line toward the right due to pressure support stemming from fluids that move from the matrix toward the fractures. Eventually, a pressure equilibrium is reached and a second straight line, parallel to the first one, is developed. However, in the case of the model presented in this paper the data deviates, not to the right of the first straight line, but down and below the first straight line. This pressure drop is interpreted to be the result of boundary-dominated flow. Next, a pressure equilibrium is reached between matrix and fractures, and the last line becomes parallel to the first straight line. It is shown that correct pressure and derivative matches permit estimating various parameter of interest such as size of the matrix blocks, number of fractures that intercept the well bore, storativity ratio omega, partitioning coefficient (the ratio between fracture and matrix porosity), matrix permeability, and the ratio of fracture to matrix hydraulic diffusivity. The novelty of this study is the development of a new easy-to-use well testing model for matching an unconventional pressure response during drawdown of a horizontal well that penetrates an unconventional tight dual porosity reservoir. The new method is explained with a step-by-step example that uses real data from the giant unconventional Chicontepec paleochannel in Mexico and can be reproduced readily by the reader.
- North America > Canada (0.28)
- North America > Mexico (0.25)
Abstract In order to properly conduct material balance calculations, the wells must be producing from the same reservoir. Identification and grouping of wells in a common reservoir can be a challenging task. The Flowing Material Balance Model (FMB model) was developed. It utilizes a wellโs flow rate and flowing pressure history to identify which wells belong in the same reservoir, and which do not. This FMB Model continuously converts the flowing pressures and rates of each well into the average reservoir pressure. If these average reservoir pressure trends overlap, it indicates that the wells are in the same reservoir. If any of the trends are different, then those wells belong to different reservoirs. The average reservoir pressure is determined in two ways. The first is from the productivity index and the flowing rates and pressures of that well. The second is from the material balance equation for the total production of the group of wells. These two average reservoir pressure trends will track over time if the well grouping is properly defined (i.e. all the wells in that grouping belong to the same reservoir), and if the correct hydrocarbon-in-place is used. The FMB Model can additionally be used to history-match the flowing pressure of each well (using the flow rate as a control) or to match the flow rate of each well (using the flowing pressure as a control). These visual history matches increase our confidence in the interpretation of the flowing material balance, and can be used to investigate the sensitivity of magnitude of the hydrocarbons-in-place One field study consisting of three adjacent gas wells, coming on production at different times, and some of the wells not having a reliable initial pressure, illustrates clearly which wells are in the same reservoir and which ones are not, and yields the correct values of original-gas-in-place.
- 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 Simulation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (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)
Abstract This paper develops a new method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. Development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with more than 0.1md. The method is calibrated with data from cores and cuttings and allows estimating the presence of grainstone, packstone and wackstone rocks in unconventional tight carbonates from well logs. A crossplot of RFN vs rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that is supported by well testing data. Information for analysis of the Mexican carbonate comes from well logs of 9 wells and 2 re-entry wells, four buildup tests and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95 percent of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md. Thus, the need for a methodology that allows estimating from well logs the presence of grainstone, packstone and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico. The novelty of this paper is the use of rock fabric (RFN) in unconventional tight carbonates with permeabilities smaller than 0.1 md for estimating the presence of grainstone, packstone and wackstone rocks from well logs. In addition, a crossplot of RFN vs rp35 provides a good indication of intervals with oil production potential.
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Turonian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Cenomanian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Aptian (0.46)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Albian (0.46)
- North America > Mexico > Tamaulipas > Burgos Basin (0.98)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.98)
- North America > Mexico > Coahuila > Burgos Basin (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Quantitative Research on Development Status of Heterogeneous Reservoirs in Offshore Oilfields
Guan, Cuo (China National Offshore Oil Corporation Research Institute Co. Ltd) | Zhang, Jian (State Key Laboratory of Offshore Oil Exploitation) | Li, Xianjie (China National Offshore Oil Corporation Research Institute Co. Ltd)
Abstract Multi-layered reservoirs have unbalanced production levels due to the contradictions between layers in offshore oilfields. At present, there is a lack of rapid and effective methods to quantitatively analyze and evaluate the development status. In this paper, based on the B-L theory and the equivalent seepage resistance method in the water drive process, a relationship chart between the average saturation of a single layer and the seepage resistance between injection and production wells is established. Using the test results of single well pressure and production well profile, single layer seepage resistance can be obtained, combined with saturation-seepage resistance chart to obtain single layer average water saturation, and then the single layer recovery degree at the time of testing can be determined. In order to establish a Lorentz curve model describing the relationship between the cumulative single layer recovery ratio (or fluid absorption index) and the ratio of formation coefficient, the recovery degree (or liquid absorption index) of each single layer and its corresponding formation coefficient are counted. Based on that Lorentz curve model, it can effectively quantify and characterize the production equilibrium degree of multi-layer reservoirs. After using this method to backcalculate the development status of a certain well group in the Bohai Oilfield, the characteristics of the degree of production and the development of large channels in each layer can be obtained. it also quantifies that the imbalance index used by the well group has risen from 1.2 in 2014 to 2.1 in 2019. This paper proposes a new method for analyzing reservoir development dynamic characteristics, which can more objectively and truly evaluate reservoir development characteristics and quantitatively evaluate the effects of adjustment measures, and provide efficient and fast technical support for the efficient development of offshore fields.
- Asia > Middle East (0.46)
- Asia > China (0.29)
- North America > United States (0.28)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Zubair Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Shuaiba Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Rumaila Field > Nahr Umr Formation (0.99)
- Asia > China > Qinghai > Qaidam Basin > Sebei Field (0.99)
Estimating Carbon Storage Capacity of Depleted Shales with Flow Regime Diagnosis and Transient Analysis
Chu, Hongyang (School of Civil and Resources Engineering, University of Science and Technology Beijing, China / State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, China / Harold Vance Department of Petroleum Engineering, Texas A&M university, College Station, USA) | Ma, Tianbi (Petroleum Exploration and Production Research Institute, SINOPEC, Beijing, China / Department of Geosciences, The University of Tulsa, Tulsa, USA) | Gao, Yubao (School of Civil and Resources Engineering, University of Science and Technology Beijing, Beijing, China) | Zhu, Weiyao (School of Civil and Resources Engineering, University of Science and Technology Beijing, Beijing, China)
Abstract Recently, many attempts have been made to estimate carbon storage capacity of depleted shales. In this paper, based on flow regime diagnosis and transient analysis, a quick and reasonable semi-analytical method for estimating CO2 storage capacity of depleted shales is introduced. Our semi-analytical method has the capability to estimate carbon storage capacity of depleted shales by considering effective diffusion, gas adsorption, and stress-sensitivity phenomenon of the permeability. By combining Laplace transforms, Pedrosa's substitution, and Stehfest numerical inversion, a CO2 seepage model for an injection well with constant injection rate is solved. With these solutions, CO2 storage capacity can be easily estimated at an arbitrary injection rate. We verify the semi-analytical method against the numerical method. In addition, the influence of some critical parameters on CO2 storage capacity are studied. Accurate determination of maximal carbon storage capacity in depleted shales is significant. This study presents a new semianalytical approach to efficiently estimate the maximal carbon storage capacity. Our study provides an improved understanding of calculating the maximal carbon storage capacity in depleted shales.
- Asia (0.96)
- North America > United States > Texas (0.28)
Summary Negative tests, or inflow tests, are conducted to verify the integrity of well barriers in the direction of potential flow, subjecting a barrier to a negative pressure differential, while monitoring for signs of a leak. A common practice is to observe the rate of flowback from the well. Flowback may be a sign of a leak due to an influx of formation fluids into the well. However, even when there is no leak, flowback is commonly observed due to thermal expansion of wellbore fluids. Heat transfer will occur between the wellbore fluids in each annulus and with the surrounding formation until temperatures reach an equilibrium. This behavior is described by the process of thermal diffusion, with the resulting temperature increase causing expansion of wellbore fluids and flowback from the well. Industry guidelines state โHornerโ analysis may be used when monitoring flowback or pressure buildup during an inflow test. In doing so, engineers and wellsite supervisors may use a โHorner plotโ to determine if flowback or pressure buildup is attributable to thermal effects. Those without a reservoir engineering background may not be aware the method was originally derived from a radial flow equation for the purpose of monitoring pressure buildup in a well when shut in after a period of production. The apparent similarity of the radial flow and thermal diffusion equations is what led Horner's technique to subsequently be applied to the prediction of static formation temperature from well logs. However, although thermal expansion is a function of formation temperature, Horner analysis of flowback or pressure buildup during an inflow test has remained a black box that is poorly understood. For the first time, with support from empirical data from offshore wells, we reveal that Horner analysis of thermal expansion is a practice without theoretical justification. The radial equation on which Horner analysis depends, along with the constraints implied by the boundary conditions, fails to accurately account for the conditions of an inflow test. As a result, the method should not be used for analyzing flowback or pressure buildup during an inflow test. Instead, a new method is proposed to interpret a trend of flowback when monitoring well barriers. The findings of this study can help improve understanding Horner analysis and techniques for interpreting inflow tests.
Abstract This paper provides the theoretical and practical basis for application of multi-segment Arps production decline models, particularly for multi-fractured horizontal wells used to develop ultra-low permeability resources. Two- and three-segment Arps models have been used in the industry for production forecasting, but the application is usually based on empirical observations and intuitive assumptions. This paper provides the basis for dividing production history of these wells into at least four segments. We first examined rigorous solutions to governing flow equations for idealized conditions and found the basis to expect (1) early transient linear flow with b โก 2; (2) a transition flow regime between transient and boundary-dominated flow (BDF) regimes with continuously changing b about one log-cycle in duration; and (3) BDF with b โก 0 for an incompressible fluid. We examined the basis for the Fetkovich type curve, which include BDF stems for compressible fluids with b values ranging from 0 to 1, and found evidence that, under most circumstances, b values should range from 0.4 to 0.5 for gas wells and 0.3 to 0.4 for depletion-drive oil wells. Durations of these flow regimes can be identified using log-log plots of pressure-normalized rate vs. time (preferable) or simply rate vs. time when pressure data are not available. Analysis of the Arps hyperbolic decline model indicates that straight lines with slopes = 1/b are expected during times with unchanging b. We found that, for multi-fractured horizontal wells, at least four distinct flow regimes should ultimately appear in practice and are related to depth-of-investigation considerations: (1) an early ramp-up in production; (2) a transient flow regime which can last for years with essentially constant b, often near 2; (3) a transition flow regime, lasting for over a log cycle in time and with continuously changing b; and (4) BDF, with essentially constant b, and 0.3 < b < 0.5 in most cases. Additional segments may arise because of changed operational conditions or flow into the stimulated reservoir volume (SRV) from the unstimulated matrix. There is no reason to expect a terminal b of zero except for the rare case of an incompressible fluid. For forecasting production from wells in resource plays, we should include the minimum of four flow regimes, even when only transient flow has been observed in history, and we should forecast appropriate durations of flow regimes and times at which they expected to begin and end based on considerations discussed in the paper. These considerations are fundamentally important for forecasting of individual wells and for construction of typical well production profiles (TWPs, akatype wells or type curves).
Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
- Research Report > New Finding (0.34)
- Overview > Innovation (0.34)
- 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...)
Abstract An explicit solution to the general 3D point to target problem based on the minimum curvature method has been sought for more than four decades. The general case involves the trajectory's start and target points connected by two circular arcs joined by a straight line with the position and direction defined at both ends. It is known that the solutions are multi-valued and efficient iterative schemes to find the principal root have been established. This construction is an essential component of all major trajectory construction packages. However, convergence issues have been reported in cases where the intermediate tangent section is either small or vanishes and rigorous mathematical conditions under which solutions are both possible and are guaranteed to converge have not been published. An implicit expression has now been determined that enables all the roots to be identified and permits either exact, or polynomial type solution methods to be employed. Most historical attempts at solving the problem have been purely algebraic, but a geometric interpretation of related problems has been attempted, showing that a single circular arc and a tangent section can be encapsulated in the surface of a horn torus. These ideas have now been extended, revealing that the solution to the general 3D point to target problem can be represented as a 10 order self-intersecting geometric surface, characterised by the trajectory's start and end points, the radii of the two arcs and the length of the tangent section. An outline of the solution's derivation is provided in the paper together with complete details of the general expression and its various degenerate forms so that readers can implement the algorithms for practical application. Most of the degenerate conditions reduce the order of the governing equation. Full details of the critical and degenerate conditions are also provided and together these indicate the most convenient solution method for each case. In the presence of a tangent section the principal root is still most easily obtained using an iterative scheme, but the mathematical constraints are now known. It is also shown that all other cases degenerate to quadratic forms that can be solved using conventional methods. It is shown how the general expression for the general point to target problem can be modified to give the known solutions to the 3D landing problem and how the example in the published works on this subject is much simplified by the geometric, rather than algebraic treatment.