Flowing Material Balance Research Articles

Application of dynamic material balance to evaluate oil wells in Buzurgan oil field

The Material Balance Equation is a crucial tool utilized in reservoir studies to evaluate fluids and rock properties at static pressures. The Flowing and Dynamic Material Balance methods offer a significant advantage by avoiding the requirement to shut down wells, as they use flowing pressure instead of static pressure under constant or variable flow rates. The concept of "Dynamic Material Balance" involves converting the bottom hole flowing pressure at any point at any given time to the average reservoir pressure at that point. This allows for the use of classical material balance calculations and the development of classical material balance plots. In this study, the Dynamic Material Balance and Agrawal Type Curve techniques were used to estimate average reservoir pressures, initial hydrocarbon in place, and ultimate oil recovery for a well in the Mishrif reservoir, the main reservoir in the Buzurgan oil field. Many wells in this field experience problems such as high-pressure decline or continuous water production, necessitating ongoing evaluation. While the Dynamic Material Balance method focuses on boundary-dominated flow data, the Agrawal-type curve technique analyzes data from both transient and boundary flow periods. Agarwal decline curves were constructed using relationships of pseudo pressure normalized production, material balance pseudo time, and dimensionless variables in well-test analysis. The results from both methods showed comparable results with an absolute percentage error of (0.738) %, (3.07) %, and 5.7% for oil-in-place, drainage area, and average reservoir pressure, respectively. This strong correlation between the Dynamic Material Balance and Type Curve results indicates their accuracy and reliability.

Calculation Model of Drainage Radius of Single-Layer/Multi-Layer Commingled Gas Production Wells in a Closed Constant-Volume Gas Reservoir and Its Application

Gas drainage radius is the most important parameter for determining reasonable well spacing. However, the drainage radius of both single-layer and multi-layer commingled gas production wells cannot be directly obtained through reservoir well tests. In order to address the above challenge, for single-layer gas production wells in a closed constant-volume gas reservoir, a calculation model for drainage radius is derived using the modified flowing material balance method. The results indicate that the calculated error of this model is only 0.73% and much smaller than that of the flowing material balance method (5.78%), implying its high accuracy. For multi-layer commingled gas production wells, another calculation model of drainage radius is established by coupling the pseudo-steady-state production capacity equation with the material balance principle. The research results demonstrate that the novel calculation model has a maximum relative error of only 2.33% and requires only two production profile tests to rapidly calculate the drainage radius of each layer within the gas reservoir, suggesting its satisfactory simplicity, significant efficiency and high precision. The proposed calculation models of drainage radius achieve a convenient and rapid calculation for both single-layer and multi-layer commingled gas production wells, and fill the theoretical gap in efficient calculation of drainage radius for a closed constant-volume gas reservoir.

A Semi-Analytical Model for Production Prediction of Deep CBM Wells Considering Gas-Water Two-Phase Flow

The productivity prediction of deep coalbed methane (CBM) wells is significantly influenced by gas-water two-phase flow characteristics and seepage parameters of the fracture network. While numerical simulations offer a comprehensive approach, analytical models are favored for their faster and broader applicability. However, conventional analytical models often oversimplify the complex problem of two-phase seepage equations, leading to substantial errors in dynamic analysis outcomes. Addressing this shortcoming, we establish a gas-water two-phase productivity prediction model for deep CBM reservoirs. This model takes into account the two-phase flow characteristics within the reservoir and fracture network, as well as the stress sensitivity of the reservoir and fractures. Additionally, a modified trilinear flow model characterizes the fractured modification body. By integrating the flowing material balance equation with the Newton Iteration method, we gradually update the seepage model’s nonlinear parameters using the average formation pressure. We also linearize the gas-water two-phase model through successive iterations to derive a semi-analytical solution. The accuracy of the model was verified through comparison with commercial numerical simulation software results and field application. The model also enabled us to scrutinize the influence of reservoir and fracture network parameters on productivity. Our research findings suggest that the semi-analytical solution approach can efficiently address the nonlinear seepage problem of gas-water two-phase flow, enabling quick and accurate prediction of deep CBM well productivity. Moreover, appropriate fracture network parameters are paramount for enhancing the productivity of deep CBM wells. Lastly, during the development of deep CBM reservoirs, it is crucial to control the production pressure difference appropriately to minimize the stress sensitivity impact on production capacity.

Study on development methods of different types of gas wells in tight sandstone gas reservoirs

Reasonable production allocation of tight sandstone gas reservoirs is an important basis for efficient development of gas wells. Taking Block XX in Ordos Basin as an example, the modified flowing material balance equation was established considering the variation of gas viscosity and compression coefficient, the advantages and disadvantages of the method were discussed, and a reasonable production allocation process for gas wells was developed. The results show that: ① The commonly used flow material balance method ignores the change of natural gas compression coefficient, viscosity and deviation coefficient in the production process. The slope of the relationship curve between bottom hole pressure and cumulative production and the slope of the relationship curve between average formation pressure and cumulative production are not equal After considering this change. Compared with the results calculated by the material balance method, the results calculated by the flow material balance method are smaller. ② The production of 660 gas wells in the study area during stable production period is verified. Compared with the open flow method, the dynamic reserve allocation method is better, with an error of 0.06%. ③ The new method in this paper is used to allocate production for different types of gas wells. The cumulative production of different types of gas wells shows different degrees of increase. The I, II, III and IV types of gas wells increase by 32.26%, 30.29%, 23.58% and 25.07% respectively. This study provides technical support for dynamic reserve calculation and reasonable production allocation of gas wells in the study area, and has important guiding significance for the formulation of reasonable development plan and economic and efficient development of tight sandstone gas reservoirs.

Rate transient analysis methods for water-producing gas wells in tight reservoirs with mobile water

Tight gas reservoirs with mobile water exhibit multi-phase flow and high stress sensitivity. Accurately analyzing the reservoir and well parameters using conventional single-phase rate transient analysis methods proves challenging. This study introduces novel rate transient analysis methods incorporating evaluation processes based on the conventional flowing material balance method and the Blasingame type-curve method to examine fractured gas wells producing water. By positing a gas-water two-phase equivalent homogenous phase that considers characteristics of mobile water, gas, and high stress sensitivity, the conventional single-phase rate transient analysis methods can be applied by integrating the phase's characteristics and defining the phase's normalized parameters and material balance pseudo-time. The rate transient analysis methods based on the equivalent homogenous phase can be used to quantitatively assess the parameters of wells and gas reservoirs, such as original gas-in-place, fracture half-length, reservoir permeability, and well drainage radius. This facilitates the analysis of production dynamics of fractured wells and well-controlled areas, subsequently aiding in locating residual gas and guiding the configuration of well patterns. The specific evaluation processes are detailed. Additionally, a numerical simulation mechanism model was constructed to verify the reliability of the developed methods. The methods introduced have been successfully implemented in field water-producing gas wells within tight gas reservoirs containing mobile water.

Estimating formation and fracturing water production using simple diagnostic plots

The main goal of this paper is to evaluate the possibility of distinguishing between formation and fracturing water based on the water-flowback response without analyzing water chemical data. We analyze flowback production data of 100 multi-fractured horizontal oil wells completed in the Montney Formation and 89 oil and gas wells completed in the Duvernay and Horn River formations. We hypothesize that 1) the slope of water-flowback harmonic decline (HD) profiles (mHD) is proportional to the slope of rate-normalized pressure (RNP) plots (mRNP), and 2) both mRNP and mHD are inversely proportional to the amount of water influx from matrix into fractures. To verify our hypothesis, we 1) extend the previous HD and single-phase flowing material balance models by considering the water influx from matrix into fractures, 2) classify the studied wells based on observed trends, 3) construct RNP diagnostic plots of the studied wells, 4) investigate the relationship between mHD and mRNP, 5) analyze log data and estimate average initial water saturation (Swi) for the studied wells, and 6) investigate the relationship between of mHD and Swi. The results show that mHD for all the studied wells ranges from 0.00001 to 0.036 1/ m3 with a mean value of 0.0056 1/ m3. Wells with higher mHD have relatively higher mRNP values. In contrast, wells with very low mHD show no significant decline in water rate through the entire flowback process and relatively low or inconsistent mRNP values on the corresponding plots of RNP versus material balance time (MBT). We also observe a negative correlation between mHD and Swi obtained by analysis of wireline log data. This correlation and the positive correlation between mHD and mRNP indicate that as Swi increases, water influx from matrix to fracture increases, and thus, both mHD and mRNP decrease. Based on our modified models and the observed correlations, we develop a method to approximately differentiate between formation and fracturing water. The applications of our heuristic method on field data shows that 1) fracturing water production dominates the total water recovery for wells with higher mRNP, and 2) formation water production dominates the total water recovery for wells with lower mRNP.

A Semi-Analytical Model for Gas–Water Two-Phase Productivity Prediction of Carbonate Gas Reservoirs

The productivity prediction of gas wells in carbonate gas reservoirs is greatly affected by the characteristics of gas–water two-phase flow and fracture seepage parameters. Compared with numerical simulation, the productivity prediction based on the analytical model is fast and widely used, but the traditional analytical model is fairly simplified while dealing with the nonlinear problem of the two-phase seepage equation, leading to a large discrepancy in the results of dynamic analysis. To solve this problem, this paper considers the characteristics of gas–water two-phase flow in the reservoir and fracture, uses the dual-medium model to characterize the stress sensitivity of the fracture and reservoir, and establishes a gas–water two-phase productivity prediction model for carbonate gas reservoirs. Combining the flowing material balance equation with the Newton iteration method, the nonlinear parameters of the percolation model are updated step by step with the use of average formation pressure, and the gas–water two-phase model is linearized through successive iterations to obtain the semi-analytical solution of the model. The accuracy of the model was verified using a comparison with the results of commercial numerical simulation software and field application, the gas–water two-phase productivity prediction curve was obtained, and the influence of sensitive parameters on productivity was analyzed. The results show that: (1) the semi-analytical solution method can efficiently deal with the gas–water two-phase nonlinear seepage problem and obtain the productivity prediction curve of carbonate gas wells rapidly and (2) the water production of the carbonate gas reservoir seriously affects the productivity of gas wells. During the development process, the production pressure difference should be reasonably controlled to reduce the negative impact of stress sensitivity on productivity performance.

Study on reasonable production allocation method of tight sandstone gas reservoir—A case of XX block in ordos basin

Reasonable production allocation of tight sandstone gas reservoirs is an important basis for efficient development of wells. Combining multiple mathematical models, the modified flowing material balance equation was established considering the variation of viscosity and compressibility, and a reasonable production allocation process was developed. The results show that: ① The flow material balance method ignores the change of compressibility, viscosity and deviation coefficient in the calculation. Compared with the results calculated by the material balance method, the results of the flow material balance method are smaller. ② A modified flowing material balance method is established, verified by the production of 670 wells in the study area during stable period. Compared with the open flow rate method, the error of dynamic reserve allocation method is smaller, with an error of 0.07%. ③ When dynamic reserves are used to allocate production, the initial decline rate of wells is reduced by 74.65% on average, the production on stable period increases by 21.28%, and the time increases by 1.79%. This study provides support for dynamic reserve calculation and reasonable production allocation of gas wells in the study area, and has important guiding significance for the formulation of reasonable development plan and economic and efficient development of tight sandstone gas reservoirs.

A new approach to production data analysis of non-volumetric naturally fractured gas condensate reservoirs

A significant amount of hydrocarbon exists in naturally fractured formations. Due to the limitations of classical reservoir evaluation methods, the ongoing researches have focused on the analysis of production data to describe reservoir dynamic. Among the existing methods, the flowing material balance (FMB) technique brings a straightforward and accurate method of reserve estimation. Often, the same approach as the single porosity reservoirs are utilized for naturally fractured formations and fewer studies have been performed with the dual-porosity model. Regarding the importance of such reservoir types, the purpose of this study is to propose a new production data analysis approach by implication of a modified compressibility parameter to the conventional FMB equations to achieve an accurate estimation of initial gas in place and average reservoir pressure in non-volumetric naturally fractured gas condensate reservoir. In the current study, we applied the aquifer influence on reservoir performance in the FMB equation by a modified isothermal rock compressibility factor, without using complex multi-phase reservoir modeling. Due to inherent uncertainty associated with aquifer parameters, the production data analysis in this study proceeded in two phases. In the first phase with the assumption of known aquifer parameters, output data were obtained. In the second phase, based on the best-fitted aquifer parameters in advance, the impact of variation of aquifer input data on the validity of output results was studied using the Monte-Carlo simulation approach. To validate the proposed method, different simulation models with variable reservoir and fluid properties were defined and the results were compared against a commercial compositional simulator. The obtained results proved the accuracy of the proposed method. Therefore, applying the modified rock compressibility in the conventional FMB method would result in a simple yet accurate method that requires the least input data to estimate initial gas in place and average reservoir pressure.

Modified Flowing Material Balance Equation for Shale Gas Reservoirs

To determine original gas-in-place, this study establishes a flowing material balance equation based on the improved material balance equation for shale gas reservoirs. The method considers the free gas in the matrix and fracture, the dissolved gas in kerogen, and the pore volume occupied by adsorbed phase simultaneously, overcoming the problem of incomplete consideration in the earlier models. It also integrates the material balance method with the flowing material balance method to obtain the average formation pressure, eliminating the problem with the previous method where shutting down of wells was needed to monitor the formation pressure. The volume of the adsorbed gas on the ground is converted into volume of the adsorbed phase in the formation using the volume conservation method to characterize the pore volume occupied by the adsorbed phase, which solves the problem of the previous model that the adsorbed phase was neglected in the pore volume. The model proposed in this study is applied to the Fuling Shale Gas Field in southwest China and compared with other flowing material balance equations, and the results show that the single-well control area calculated by the model proposed in this study is closer to the real value, indicating that the calculations in this study are more accurate. Furthermore, the calculations show that the dissolved gas takes up a large fraction of the total reserves and cannot be ignored. The sensitivity analyses of critical parameters demonstrate that (a) the greater the porosity of the fracture, the greater the free gas storage; (b) the values of Langmuir volume and TOC can significantly affect the results of the reservoir calculation; and (c) the adsorbed phase occupies a smaller pore volume when the Langmuir volume is smaller, the Langmuir pressure is higher, or the adsorbed phase density is higher. The findings of this study can provide better understanding of the necessity to take into account the dissolved gas in the kerogen, the pore volume occupied by the adsorbed phase, and the fracture porosity when evaluating reserves. The method could be applied to the calculation of pressure, recovery of free gas phase and adsorbed phase, original gas-in-place, and production predictions, which could help for better guidance of reserve potential estimations and development strategies of shale gas reservoirs.

First-time implementation of multiple flowback DFITs (“DFIT-FBA”) along a horizontal well

The DFIT flowback analysis (DFIT-FBA) method is a new approach for obtaining closure pressure (pc), a proxy for minimum in-situ stress, reservoir pressure (pr), and well productivity index (J) estimates in a fraction of the time required by conventional (pump-in/falloff) DFITs. The time and cost efficiency associated with the DFIT-FBA method provides an opportunity to conduct multiple field tests without delaying drilling and completion programs. The primary novelty of the current study is the first-time demonstration of the implementation and analysis of multiple DFIT-FBA tests along a horizontal well completed in an unconventional reservoir to investigate variations in pc, pr, and J. Furthermore, new corrections are introduced for the DFIT-FBA method to account for perforation friction, tortuosity, and wellbore unloading during the flowback stage of the test.Three DFIT-FBA tests were performed in the studied lateral, including at the toe, at a middle stage and near the heel of the lateral. Minimum in-situ stress, pore pressure, and well productivity index estimates were successfully obtained for all the DFIT-FBA tests and verified with the results of a conventional DFIT, also performed at the toe of the studied well. The new corrections for friction and wellbore unloading improved the accuracy of the closure and reservoir pressures by 4%. Furthermore, the results of flowing material balance analysis demonstrate that wellbore unloading might cause significant over-estimation of the well productivity index.Considerable variation in well productivity index was observed from the toe stage to the heel stage (along the lateral) for the studied well, as determined using DFIT-FBA. This variation has significant implications for hydraulic fracture design optimization, particularly treatment pressures and volumes.

Using the Flowing Material Balance Model to Determine Which Wells Out of a Group of Wells belong to the Same Common Pool

Summary 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. Based on the flowing material balance (FMB), a methodology was developed that utilizes a well’s flow rate and flowing pressure history to identify which wells belong in the same reservoir, and which do not. This methodology, called the 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 (PI) 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 FMB 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.

Two-phase Flow Model and Productivity Evaluation of Gas and Water for Dual-Medium Carbonate Gas Reservoirs

Fluid flow in the dual-medium carbonate gas reservoir is characterized by stress sensitivity and non-Darcy flow effect. In order to accurately describe the unsteady flow of gas and water in the dual-medium gas reservoir, a two-phase flow model of gas and water is built. First, reservoir space and fluid flow characteristics of carbonate gas reservoirs are investigated, and the flow model that considers both the stress sensitivity and non-Darcy flow is built based on the fundamental flow theory, after fully investigating the reservoir space and fluid flow characteristics of carbonate gas reservoirs. Then, the perturbation theory is introduced, and the model is solved in the Laplace space, after which the obtained Laplace space analytical solution is converted into the real-space solution. Finally, the productivity evaluation model for the dual-medium gas reservoir with the gas-water two-phase flow is built, based on the flowing material balance method and Newton iteration. The presented productivity evaluation model is applied to analyze the effects of stress sensitivity and non-Darcy flow on the two-phase flow model of gas and water for the dual-medium gas reservoir and the reservoir productivity. The results indicate that a higher stress sensitivity coefficient is demonstrated to indicate higher stress sensitivity and accelerated production decline of the reservoir, while a lower non-Darcy flow effect coefficient represents a stronger non-Darcy effect and boosted drop of initial production of the reservoir. Hence, it is not reasonable to neglect the effects of stress sensitivity and non-Darcy flow during the evaluation of the productivity of a dual-medium carbonate gas reservoir. The model presented in this research provides important references for improving the recovery performance of dual-medium gas reservoirs.

Modifying rock compressibility to analyze the production data of non-volumetric gas and gas condensate reservoirs

Production data analysis, particularly the flowing material balance method, has been used for many years as an efficient, practical, and significant method to obtain important reservoir parameters. Many studies have been done to develop the flowing material balance method in different types of reservoirs which in most of them, the main limitation is that the reservoir has been considered to be volumetric. Therefore, despite being widely used, this method has not been well developed for non-volumetric water drive reservoirs. In the present work, an extremely simple yet very accurate method was introduced to obtain an excellent estimation of average pressure and gas in place of non-volumetric dry gas and gas condensate reservoirs. In our proposed method, a modified rock compressibility parameter was presented to modify current flowing material balance equations which have been developed for volumetric dry gas and gas condensate reservoirs previously. Using the proposed compressibility, the modified flowing material balance equations can be used for non-volumetric dry gas and gas condensate reservoirs producing with constant bottomhole pressure during the boundary-dominated flow period. Moreover, the iterative procedures to estimate average pressure and gas in place of these kinds of reservoirs were presented in detailed steps. Also, the validity of the proposed flowing material balance equations was performed using a commercial numerical reservoir simulator. The obtained results prove the efficiency of the proposed method. Furthermore, due to the high amount of uncertainty in aquifer parameters, an uncertainty analysis has been performed on aquifer parameters using Monte-Carlo simulation. The results of the study indicated that the determination of appropriate aquifer parameters has a significant impact on the estimation of reservoir parameters which can be obtained using a combination of uncertainty analysis and the proposed flowing material balance technique.

Applicability of the flowing material balance method to heterogeneous reservoirs

The flowing material balance (FMB) method is widely used to evaluate geological reserves because it does not require shut-in wells and uses daily production data. The original FMB method is based on a homogeneous medium model, but the reservoir is often heterogeneous. In this study, FMB equations are derived for radial composite reservoirs and naturally fractured reservoirs, and the effect of reservoir parameters on the estimation of geological reserves is analyzed. The study found that in order to obtain accurate geological reserves, the average formation total compressibility should be used. Inappropriate total compressibility may cause significant errors. Finally, the proposed method is validated by a case study.

A Semianalytical Model for Analyzing the Infill Well-Caused Fracture Interference from Shale Gas Reservoirs

Drilling infill well has been widely used in many plays to enhance the recovery of shale gas, but the infill well-caused fracture interference is a very important issue that should be taken into consideration. The well interference makes it difficult for the conventional models to make production predictions, fracture characterization, and production data analysis. In this paper, a semianalytical model is proposed for this purpose by discretizing the whole control volume of the parent and infill wells into several linear flow zones. In this way, three important issues can be further handled very naturally, including fracture connection between the parent and infill wells, different SRV properties for zones with different distances to the wellbore, and different production times for adjacent wellbores. The approximate expressions for different flow regimes are used in making production predictions in the time domain, and a flowing material balance method and a simple iteration are used to update the model parameters step by step. The proposed model is shown to be reasonable and accurate for handling multiwell interference problems after comparing with the commercial numerical simulator tNavigator. The synthetical cases show that the fracture parameters, SRV properties, and well infill time have a significant influence on the production performance of both the parent and infill wells. The results show that the production of the parent well will be dramatically enhanced when it is connected with the infill well via high-conductive hydraulic fractures. Longer unconnected fractures and more fracturing stages/clusters for the infill well will result in higher production for the infill well, but a negative effect is observed for the parent well. The permeability of the distant well SRV has a similar influence on the parent and infill wells. The results also show that late time well interference will result in a more significant increase in production rate on the log-log plots for the severe depletion around the parent well. Finally, the proposed model is used to analyze the production data of a field case from Fuling shale in Southwestern China. After analyzing the production data, several parameters can be obtained for both parent and infill wells, including the fracture lengths and conductivities, numbers of connected fractures, and the near and distant well permeabilities of the SRV. This gives a basic and practical technique for production prediction, formation and fracture evaluation, and well connectivity analysis from shale gas wells with fracture connection.

Post-Frac Evaluation of Horizontal Wells Producing Shale/Tight Reservoirs with Early Flowback History

The early flowback history of fracturing fluid can be used to evaluate the effect of multi-stage fracturing for horizontal wells, and the effective fracture pore volume is the critical parameter to reflect the fracturing effectiveness. However, the current calculation method of effective fracture pore volume based on the flowback history has the problem of low accuracy. This paper presents a new method for quantitatively calculating the effective fracture pore volume based on flowback history. It is based on the current available methodology in North America, using the flowing material balance method of Rate Transient Analysis (RTA), combined with the traditional production decline method. Taking a domestic tight oil multi-stage fracturing horizontal well as an example, The workflow of this new methodology is illustrated in detail. The calculation results show that only 21% of the injected fracturing fluid contributes to the fracture conductivity. The example results show that the new methodology can effectively improve the accuracy of the effective fracture pore volume.

Modification of the Calculation Method for Dynamic Reserves in Tight Sandstone Gas Reservoirs.

The determination of dynamic reserves is important for tight sandstone gas reservoirs in production. Based on the geological and gas data of the Yan’an gas field, the influence of pressure on the properties of natural gas is studied by mathematical methods. At the same time, the modified flowing material balance equation is established considering the changes in gas viscosity and compressibility. The result shows that (1) the viscosity of natural gas increases rapidly with pressure; (2) the deviation factor decreases with pressure (P < 15 MPa) and then increases (P > 15 MPa) with temperature; (3) the compressibility decreases rapidly with pressure and increases with temperature; (4) compared with the results of the material balance method, the average error of the flowing material balance method is 33.95%, and the accuracy of the modified flowing material balance method is higher with an average error of 1.25%; and (5) a large change in the production will affect the accuracy of the modified flowing material balance method, especially a shut-in for a long time before the pressure drop production is calculated at a certain time, so data points that are relatively consistent should be selected as far as possible to calculate the dynamic reserves. The findings of this study can help in the accurate evaluation of dynamic reserves of the tight gas reservoir in the Yan’an gas field and are an important guide for the formulation of a rational plan for the gas reservoir and its economic and efficient development.

Research on optimal production distribution of tight sandstone gas reservoir

The determination of dynamic reserves is an important basis for rational production allocation. Based on the Yan’an Gas Field, the modified flowing material balance equation is established considering the changes of gas viscosity and compressibility. At the same time, a reasonable production allocation method for gas wells is developed. The result shows: ① μgCg decreases with pressure and increases with temperature. ② The error of the modified flowing material balance method is smaller compared with the flow material balance method, and the error is 1.25 %. ③ The great change of the production will affect the accuracy of the modified flow material balance method, especially the shut-in for a long time before the pressure drop production is calculated at a certain time, so the points with relatively constant should be selected as far as possible. ④ When the dynamic reserves are used for allocation, the initial decline rate decreases by 74.65 % on average, and the stable production period increases by 21.28 % and the stable production period increases by 1.79 % compared with the allocation method of open flow rate. ⑤ When there is a large error of dynamic reserves, it will lead to production deviation from the reasonable value. The findings of this study can help for the accurate evaluation of dynamic reserves and reasonable production allocation of tight gas wells in the Yan’an gas field, and is an important guide for the formulation of a rational plan for the gas reservoir and its economic and efficient development.

Flowing Material Balance and Rate-Transient Analysis of Horizontal Wells in Under-Saturated Coal Seam Gas Reservoirs: A Case Study from the Qinshui Basin, China

Two phase flow and horizontal well completion pose additional challenges for rate-transient analysis (RTA) techniques in under-saturated coal seam gas (CSG) reservoirs. To better obtain reservoir parameters, a practical workflow for the two phase RTA technique is presented to extract reservoir information by the analysis of production data of a horizontal well in an under-saturated CSG reservoir. This workflow includes a flowing material balance (FMB) technique and an improved form of two phase (water + gas) RTA. At production stage of a horizontal well in under-saturated CSG reservoirs, a FMB technique was developed to extract original water in-place (OWIP) and horizontal permeability. This FMB technique involves the application of an appropriate productivity equation representing the relative position of the horizontal well in the drainage area. Then, two phase (water + gas) RTA of a horizontal well was also investigated by introducing the concept of the area of influence (AI), which enables the calculation of the water saturation during the transient formation linear flow. Finally, simulation and field examples are presented to validate and demonstrate the application of the proposed techniques. Simulation results indicate that the proposed FMB technique accurately predicts OWIP and coal permeability when an appropriate productivity equation is selected. The field application of the proposed methods is demonstrated by analysis of production data of a horizontal CSG well in the Qinshui Basin, China.