A Production Performance Prediction and Field Development Tool for Coalbed Methane Reservoirs: A Proxy Modeling Approach

Abstract Proper understanding of reservoir producing mechanism forms a backbone for optimal fluid recovery in any reservoir. Such an understanding is usually fostered by a detailed petrophysical evaluation, structural interpretation, geological description and modelling as well as production performance assessment prior to history matching and reservoir simulation. In this study, gravity drainage mechanism was identified as the primary force for production in reservoir X located in Niger Delta province and this required proper model calibration using variation of vertical anisotropic ratio based on identified facies as against a single value method which does not capture heterogeneity properly. Using structural maps generated from interpretation of seismic data, and other petrophysical parameters from available well logs and core data such as porosity, permeability and facies description based on environment of deposition, a geological model capturing the structural dips, facies distribution and well locations was built. Dynamic modeling was conducted on the base case model and also on the low and high case conceptual models to capture different structural dips of the reservoir. The result from history matching of the base case model reveals that variation of vertical anisotropic ratio (i.e. kv/kh) based on identified facies across the system is more effective in capturing heterogeneity than using a deterministic value that is more popular. In addition, gas segregated fastest in the high case model with the steepest dip compared to the base and low case models. An improved dynamic model saturation match was achieved in line with the geological description and the observed reservoir performance. Quick wins scenarios were identified and this led to an additional reserve yield of over 1MMSTB. Therefore, structural control, facies type, reservoir thickness and nature of oil volatility are key forces driving the gravity drainage mechanism.

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Use of the Dual-Activity Drillship as a Field Development Tool

10.4043/10891-ms ◽

1999 ◽

Cited By ~ 2

Author(s):

Johnce E. Hall ◽

Robert P. Herrmann ◽

Charles A. Holt ◽

William J. Straub ◽

Rickey G. Weber

Keyword(s):

Field Development ◽

Development Tool

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A practical method for planning large number of horizontal wells with a reservoir model for a field development plan

Petrovietnam Journal ◽

10.47800/pvj.2021.10-02 ◽

2021 ◽

Vol 10 ◽

pp. 17-32

Author(s):

Guido Fava ◽

Việt Anh Đinh

Keyword(s):

Horizontal Well ◽

Horizontal Wells ◽

Simulation Software ◽

Production Performance ◽

Development Plan ◽

Regular Pattern ◽

Production Forecast ◽

Advanced Technique ◽

Large Reservoir ◽

Field Development

The most advanced technique to evaluate different solutions proposed for a field development plan consists of building a numerical model to simulate the production performance of each alternative. Fields covering hundreds of square kilometres frequently require a large number of wells. There are studies and software concerning optimal planning of vertical wells for the development of a field. However, only few studies cover planning of a large number of horizontal wells seeking full population on a regular pattern. One of the criteria for horizontal well planning is selecting the well positions that have the best reservoir properties and certain standoffs from oil/water contact. The wells are then ranked according to their performances. Other criteria include the geometry and spacing of the wells. Placing hundreds of well individually according to these criteria is highly time consuming and can become impossible under time restraints. A method for planning a large number of horizontal wells in a regular pattern in a simulation model significantly reduces the time required for a reservoir production forecast using simulation software. The proposed method is implemented by a computer script and takes into account not only the aforementioned criteria, but also new well requirements concerning existing wells, development area boundaries, and reservoir geological structure features. Some of the conclusions drawn from a study on this method are (1) the new method saves a significant amount of working hours and avoids human errors, especially when many development scenarios need to be considered; (2) a large reservoir with hundreds of wells may have infinite possible solutions, and this approach has the aim of giving the most significant one; and (3) a horizontal well planning module would be a useful tool for commercial simulation software to ease engineers' tasks.

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An Empirical Analog Benchmarking Workflow to Improve Hydrocarbon Recovery

SPE Reservoir Evaluation & Engineering ◽

10.2118/208612-pa ◽

2021 ◽

pp. 1-18

Author(s):

Shaoqing Sun ◽

David A. Pollitt

Keyword(s):

Best Practices ◽

Lessons Learned ◽

Production Performance ◽

Resource Potential ◽

Systematic Analysis ◽

Hydrocarbon Recovery ◽

Field Development ◽

Development Scenarios ◽

Recovery Potential ◽

Wide Range

Summary Benchmarking the recovery factor and production performance of a given reservoir against applicable analogs is a key step in field development optimization and a prerequisite in understanding the necessary actions required to improve hydrocarbon recovery. Existing benchmarking methods are principally structured to solve specific problems in individual situations and, consequently, are difficult to apply widely and consistently. This study presents an alternative empirical analog benchmarking workflow that is based upon systematic analysis of more than 1,600 reservoirs from around the world. This workflow is designed for effective, practical, and repeatable application of analog analysis to all reservoir types, development scenarios, and production challenges. It comprises five key steps: (1) definition of problems and objectives; (2) parameterization of the target reservoir; (3) quantification of resource potential; (4) assessment of production performance; and (5) identification of best practices and lessons learned. Problems of differing nature and for different objectives require different sets of analogs. This workflow advocates starting with a broad set of parameters to find a wide range of analogs for quantification of resource potential, followed by a narrowly defined set of parameters to find relevant analogs for assessment of production performance. During subsequent analysis of the chosen analogs, the focus is on isolating specific critical issues and identifying a smaller number of applicable analogs that more closely match the target reservoir with the aim to document both best practices and lessons learned. This workflow aims to inform decisions by identifying the best-in-class performers and examining in detail what differentiates them. It has been successfully applied to improve hydrocarbon recovery for carbonate, clastic, and basement reservoirs globally. The case studies provided herein demonstrate that this workflow has real-world utility in the identification of upside recovery potential and specific actions that can be taken to optimize production and recovery.

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Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

10.2118/207306-ms ◽

2021 ◽

Author(s):

Nasser AlAskari ◽

Muhamad Zaki ◽

Ahmed AlJanahi ◽

Hamed AlGhadhban ◽

Eyad Ali ◽

...

Keyword(s):

Production Performance ◽

Shallow Depth ◽

Production Rates ◽

Field Development ◽

Artificial Lift ◽

Geological Conditions ◽

Fracture Fluid ◽

Reservoir Potential ◽

Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

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Development Drilling Results from Selected Deepwater Gulf of Mexico Fields - Implications on Turbidite Reservoir Characterization and Production Performance Prediction

EAGE/AAPG 3rd Research Symposium - Developing and Managing Turbidite Reservoirs ◽

10.3997/2214-4609.201406567 ◽

1998 ◽

Author(s):

G. Clemenceau ◽

J. Colbert ◽

F. Lockett ◽

B. Musso

Keyword(s):

Gulf Of Mexico ◽

Performance Prediction ◽

Reservoir Characterization ◽

Production Performance

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Optimizing Production Schedule of Coalbed Methane Wells Using a Stochastic Evolution Algorithm

Mathematical Problems in Engineering ◽

10.1155/2020/5828256 ◽

2020 ◽

Vol 2020 ◽

pp. 1-19

Author(s):

Qiujia Hu ◽

Xianmin Zhang ◽

Xiang Wang ◽

Bin Fan ◽

Huimin Jia

Keyword(s):

Production Rate ◽

Coalbed Methane ◽

Optimization Problem ◽

Production Optimization ◽

Production Performance ◽

Production Schedule ◽

Schedule Optimization ◽

Well Production ◽

Control Frequency ◽

Optimized Schedule

Production optimization of coalbed methane (CBM) is a complex constrained nonlinear programming problem. Finding an optimal decision is challenging since the coal seams are generally heterogeneous with widespread cleats, fractures, and matrix pores, and the stress sensitivities are extremely strong; the production of CBM wells needs to be adjusted dynamically within a reasonable range to fit the complex physical dynamics of CBM reservoirs to maximize profits on a long-term horizon. To address these challenges, this paper focuses on the step-down production strategy, which reduces the bottom hole pressure (BHP) step by step to expand the pressure drop radius, mitigate the formation damage, and improve CBM recovery. The mathematical model of CBM well production schedule optimization problem is formulated. The objective of the optimization model is to maximize the cumulative gas production and the variables are chosen as BHP declines of every step. BHP and its decline rate constraints are also considered in the model. Since the optimization problem is high dimensional, nonlinear with many local minima and maxima, covariance matrix adaptation evolution strategy (CMA-ES), a stochastic, derivative-free intelligent algorithm, is selected. By integrating a reservoir simulator with CMA-ES, the optimization problem can be solved successfully. Experiments including both normal wells and real featured wells are studied. Results show that CMA-ES can converge to the optimal solution efficiently. With the increase of the number of variables, the converge rate decreases rapidly. CMA-ES needs 3 or even more times number of function evaluations to converge to 100% of the optimum value comparing to 99%. The optimized schedule can better fit the heterogeneity and complex dynamic changes of CBM reservoir, resulting a higher production rate peak and a higher stable period production rate. The cumulative production under the optimized schedule can increase by 20% or even more. Moreover, the effect of the control frequency on the production schedule optimization problem is investigated. With the increases of control frequency, the converge rate decreases rapidly and the production performance increases slightly, and the optimization algorithm has a higher risk of falling into local optima. The findings of this study can help to better understanding the relationship between control strategy and CBM well production performance and provide an effective tool to determine the optimal production schedule for CBM wells.

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Effect of Pressure-Propagation Behavior on Production Performance: Implication for Advancing Low-Permeability Coalbed-Methane Recovery

SPE Journal ◽

10.2118/194021-pa ◽

2018 ◽

Vol 24 (02) ◽

pp. 681-697 ◽

Cited By ~ 9

Author(s):

Zheng Sun ◽

Juntai Shi ◽

Keliu Wu ◽

Tao Zhang ◽

Dong Feng ◽

...

Keyword(s):

Prediction Model ◽

Coalbed Methane ◽

Control Method ◽

Gas Production ◽

Production Performance ◽

Phase Flow ◽

Two Phase ◽

Propagation Behavior ◽

Flow Stage ◽

Pressure Propagation

Summary Low-permeability coalbed-methane (CBM) reservoirs possess unique pressure-propagation behavior, which can be classified further as the expansion characteristics of the drainage area and the desorption area [i.e., a formation in which the pressure is lower than the initial formation pressure and critical-desorption pressure (CDP), respectively]. Inevitably, several fluid-flow mechanisms will coexist in realistic coal seams at a certain production time, which is closely related to dynamic pressure and saturation distribution. To the best of our knowledge, a production-prediction model for CBM wells considering pressure-propagation behavior is still lacking. The objective of this work is to perform extensive investigations into the effect of pressure-propagation behavior on the gas-production performance of CBM wells. First, the pressure-squared approach is used to describe the pressure profile in the desorption area, which has been clarified as an effective-approximation method. Also, the pressure/saturation relationship that was developed in our previous research is used; therefore, saturation distribution can be obtained. Second, an efficient iteration algorithm is established to predict gas-production performance by combining a new gas-phase-productivity equation and a material-balance equation. Finally, using the proposed prediction model, we shed light on the optimization method for production strategy regarding the entire production life of CBM wells. Results show that the decrease rate of bottomhole pressure (BHP) should be slow at the water single-phase-flow stage, fast at the early gas/water two-phase-flow stage, and slow at the late gas/water two-phase-flow stage, which is referred to as the slow/fast/slow (SFS) control method. Remarkably, in the SFS control method, the decrease rate of the BHP at each period can be quantified on the basis of the proposed prediction model. To examine the applicability of the proposed SFS method, it is applied to an actual CBM well in Hancheng Field, China, and it enhances the cumulative gas production by a factor of approximately 1.65.

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