Water Drive Gas Reservoirs Research Articles

Impact of Material Balance Calculation on Trapped Gas in Water-drive Gas Reservoir

Abstract The development of water-drive gas reservoir takes a very important position in China. Not only its recovery is markedly lower than that of dry gas reservoir, but also its residual gas saturation is higher. The main reason has been proven in the lab is water invasion which can generate trapped gas by sealing gas in porous media. However, it is still difficult to calculate the volume of trapped gas theoretically and practically. In order to quantify trapped gas, we designed experiments to simulate the development of water-drive gas reservoir. The experimental system can provide accurate measurements on gas production, water influx, pressure and so on. The results showed that the original material balance equations are not consistent with experimental data when water invasion happens. With water influx increasing, the errors become more obvious. This phenomenon has been repeated for many times in our lab. On basis of this phenomenon and with the analysis of many experimental data, we observed that water influx causes some high pressure trapped gas which is not considered in original material balance equation. By regression analysis, we proposed a correction term which can be added to the original material balance equation to effectively eliminate the disagreements between the results of original equation and the experiments. The modified material balance equation was also verified by field cases. The correction term can be applied to quantify the degree of trapped gas, which is significant to calculate the water influx and to predict production and improves the original material balance equation so that the trapped gas in water-drive gas reservoir can be fully considered. The correction term is proposed through statistical regression analysis based on a large number of experimental data. The modified material balance equation with the correction term can quantify the trapped gas and have a great significant impact on the development of water-drive gas reservoir, especially on the water influx calculation and production prediction.

Review about evaluation methods of recoverable reserves of deep water drive gas reservoirs in China

It has been widely accepted that China is one of the biggest natural gas consumers. Related to the imports of LNG, China stands in a very uncomfortable situation. Most domestic gas reservoirs fall within deep water drive gas reservoirs inordinately, which has entered the production depletion stage. Accurate estimation of SEC recoverable reserves of deep water drive gas reservoirs is of great significance for gas consumption planning and peak shaving. The existing calculation methods of recoverable reserves mainly consist of static methods and dynamic methods. In the early stage of exploration and development, the volumetric method has often been utilized to calculate the recoverable reserves. With the continuous development of gas reservoirs, the main methods for evaluation are dynamic methods, including the successive subtraction of production method, water drive curve method, prediction model method, attenuation curve method, improved virtual curve method, and material balance method for deep gas reservoirs.

Improving Gas Recovery of Water Drive Gas Reservoir

A gas reservoir with bottom water drive has lower recovery factor compared to depletion drive gas reservoir. Along with the increase in gas demand and the majority of gas reservoirs are water-drive, a method that are still being developed to increase the recovey factor in water-drive gas reservoir is co-production method. This method reducing water influx by planned water production. In this study, a conceptual model of gas reservoir with depletion-drive and water-drive is build and being analyzed. Co-production technique is applied by adding one water production well to the water-drive gas reservoir. The recovery factor is being analyzed through some production scenarios. Sensitivity analysis are being done with parameters including: reservoir permeability, permeability anisotropy, aquifer volume, flow rate of water production, gas tubing head pressure, and gas well perforation interval Furthermore, experimental design, response surface methodology, and monte carlo simulation is used to analyze the influencing parameter of gas recovery factor. It is found from this study that co production increased gas recovery factor by 28% from water drive gas reservoir, with water production rate is the most influencing parameter.

A novel material-balance approach for estimating in-place volumes of gas and water in gas reservoirs with aquifer support

Applications of the traditional static material-balance method in gas reservoirs become a challenge with production maturity due to variability in aquifer influx, infill drilling, and production-operational changes in offset wells, among others. Besides, some existing modeling approaches involve a trial-and-error method, making the solution outcomes nontrivial. This study proposes a new methodology for analyzing production data involving water-drive gas reservoirs. The main findings of this study include the following: (1) A straight-line plot that yields gas and water in-place volumes, (2) A modified-(pav/z)* plot exhibits a straight-line with an x-intercept of gas initially-in-place, similar to that in a conventional-(pav/z) plot, (3) A new definition of degree of aquifer support that is quantifiable using production data. Synthetic data verified the proposed modeling approach, whereas a field dataset provided validation.

An automated data-driven pressure transient analysis of water-drive gas reservoir through the coupled machine learning and ensemble Kalman filter method

Natural gas plays a crucial role in sustaining the economic development. The production behavior of natural gas reservoir is significantly affected by the connecting aquifer. To investigate the aquifer and reservoir properties, the pressure buildup well test is conducted and the pressure transient data need to be analyzed. However, the pressure transient data analysis usually involves a procedure to build an analytical or numerical model to predict the pressure transient dynamics. With the existence of many historical records on the well test data and advancement of machine learning method, a data-driven method is proposed here to automate the well test data analysis of water-drive gas reservoir. The dataset generated from the previous well test records is used as the training set for the machine learning method. To identify the water invasion mode, the random forest classification method is introduced, and the discrete linear segment slopes are extracted from the pressure derivative curve as the feature. To predict the pressure transient dynamics, the random forest regression method is proposed to construct a projection between the aquifer/reservoir properties and the pressure transient curves. Once the water invasion mode is determined and the data-driven model to predict the pressure transient dynamic is constructed, the ensemble Kalman filter is used to estimate the aquifer/reservoir properties from the well testing data. The results show that the random forest classification method can accurately identify the water invasion mode and the random forest regression based ensemble Kalman filter method can estimate the aquifer/reservoir properties accurately with the reduced uncertainty.

How pH induced surface charge modification explains the effect of petrophysical and hydrological factors on recovery trends of water drive gas reservoirs

It is generally known that water drive oil reservoirs are more efficient than water drive gas reservoirs. In the petroleum literature, several studies have documented recovery trends based on petrophysical factors other than the wettability factor.Consistent with the high concentration of carbon dioxide in natural gas systems, the pH induced wetting transition reported in petroleum recovery research associated with low salinity water flooding is a potential factor that can impact gas recovery from natural gas systems. In this paper, we have reviewed extensively the fundamental aspects of pH induced wetting transition associated with surface charge regulation in different lithologies. In so doing, we have developed theoretical models that aid explanation of gas recovery trends from different lithologies associated with natural gas systems under aquifer drive. Most importantly, putting our models in the context of fundamental theories associated with pH induced surface charge modification, we have successfully correlated the literature based wetting transition trends of gas recovery to petrophysical properties of absolute permeability and rock type as well as hydrological effect associated with aquifer type.

Physical simulation for water invasion and water control optimization in water drive gas reservoirs

The development of water drive gas reservoirs (WDGRs) with fractures or strong heterogeneity is severely influenced by water invasion. Accurately simulating the rules of water invasion and drainage gas recovery countermeasures in fractured WDGRs, thereby revealing the mechanism of water invasion and an appropriate development strategy, is important for formulating water management measures and enhancing the recovery of gas reservoirs. In this work, physical simulation methods were proposed to gain a better understanding of water invasion and to optimize the water control of fractured WDGRs. Five groups of experiments were designed and conducted to probe the impacts of the distance between the fractures and the gas well, the drainage position, the drainage timing and the aquifer size on the water invasion and production performance of a gas reservoir. The gas and water production and the internal pressure drop were monitored in real time during the experiments. Based on the above experimental works, a theoretical analysis was conducted to quantitatively evaluate the performance of the gas reservoir recovery via the gas well production performance, water invasion, dynamic pressure drop and residual gas and water distribution analysis. The results show that when the fracture scale was appropriate, a gas well drilled close to a fracture (Experiment 1-3) or a high-permeability formation could also produce gas and achieve drainage efficiently. The recovery factor of Experiment 1-3 reached 62.5%, which was 24.6% and 21.1% higher than those of Experiments 1-1 and 1-2, respectively, which had wells drilled in low-permeability areas. Draining water near an aquifer can effectively inhibit water invasion during the early stage of gas recovery. The setup in Experiment 2-1 effectively inhibited water invasion and avoided the formation of water-sealed volumes of gas to recover 30% more gas than recovered with that of Experiment 1-1 without drainage wells. A shorter distance between the drainage well and the aquifer increased the drainage capacity and decreased the gas production capacity, respectively (Well 2 at Point A vs Point B). A larger aquifer had a lower gas recovery, which reduced the economic benefit. For example, due to an infinitely large aquifer, the reserves in Experiment 4-1 were developed by a single well, the gas recovery was only 33.4%. These research results are expected to be beneficial for the preparation of development plans and the optimization of water control measures for WDGRs.

Absolute open flow (AOF) potential evaluation for watered-out gas wells in water-drive gas reservoir

This paper presents a gas-water two-phaseLaminar-Inertial-Turbulent (LIT) flow equation for watered-out gas wells, which can be solved through the incorporation of daily production, gas-water relative permeability and PVT data, and then Q AOF and formation factor (Kh) are obtained. Field case study in Long Wang Miao (LWM) water-drive gas reservoir shows that for watered-out gas wells, the single-phase LIT equation can result in overestimation of Q AOF by 30–80%. Water invasion performance can be relieved after reducing the production rate of watered-out gas wells, and water invasion behavior before breakthrough can be diagnosed with the decline trend of Kh values.

Optimization and utilization of peak-shaving capability for water drive gas storage

To determine the reasonable gas injection and production quantity and to minimize the influence of water invasion on the operation of underground gas storage is one of the key factors to decide whether the water drive gas storage can fully exert its peak shaving ability. At present, gas reservoir engineering method is mainly used in China, which mainly reflects the operation of underground gas storage under the condition of less water invasion at the end of gas production, it cannot really reflect the influence of water invasion on the operation of underground gas storage under the condition of large injection-production volume. Through the numerical simulation and the research of the injection-production performance, it is clear that the main geological factors affecting the reasonable injection-production rate of the gas storage are the pressure of the gas storage, the properties of the reservoir, the distribution of gas and water and the radius of well control. Based on the reservoir changes of pressure, water yield, gas-water ratio, gas-water interface and saturation, and according to the influence of multi-period water invasion on the operation of gas storage, the optimization technology of peak shaving capacity of water drive gas reservoir is established, which successfully guides the optimization of injection-production operation of an underground gas storage in China. The result shows that after 5 cycles of operation, the gas injection displacement effect is successful, the gas production capacity is improved gradually, and the peak shaving capacity is 6.85 X 108m3 in 2019. The conclusion is that the optimization technology of peak shaving capacity is applicable to some extent, which provides theoretical basis and operating experience for the design of injection-production operation of the same type gas storage in China.

Discussion on evaluation method of water energy in strong water drive gas reservoir

In the process of gas reservoir development, as the pressure of gas reservoir decreases, water will invade into the gas reservoir and form a certain scale of water body, so it is very necessary to know the water body energy correctly. This paper takes strong water drive gas reservoir as an example, and uses equation of state method, pressure drop curve method and material balance method respectively to complete the water body energy evaluation of this block, so as to find the water body energy evaluation method suitable for strong water drive gas reservoir, which plays an important role in implementing water control measures.

Study of the efficiency of trapped gas displacement by non-hydrocarbon gases from water-flooded gas condensate reservoirs

Analyzing industrial data and the results of theoretical studies, it was found that the natural gas recovery factor in water-drive gas reservoirs is about 50-60%. Considering the significant volumes of residual gas reserves trapped by formation water, there is a need to improve existing development technologies and search for optimal ways to increase hydrocarbon recovery under conditions of intensive water encroaching. Additional researches using hydrodynamic simulations were conducted in order to study the efficiency of enhanced recovery of residual gas reserves by injecting non-hydrocarbon gases into productive reservoirs. Based on the 3D reservoir model, the study of carbon dioxide and nitrogen injection into the initial gas-water contact was carried out in order to slow down the breakthrough of formation water into productive reservoir. The study was performed for different injection duration of carbon dioxide and nitrogen into productive reservoir. According to the results of the statistical processing of the calculated data, the optimal duration of the nitrogen injection was determined to be 8,04 months. The ultimate gas recovery factor for the optimal period of nitrogen injection is 58,11%. At the time of the carbon dioxide breakthrough into production wells, the optimal duration of the carbon dioxide injection was determined to be 16,32 months. The ultimate gas recovery factor for the optimal period of carbon dioxide injection is 61,98 %. Based on a comparative analysis of the efficiency of using various types of non-hydrocarbon gases as injection agents into productive reservoirs, the high efficiency of using carbon dioxide for injection into the initial gas-water contact was established. Due to the solubility of carbon dioxide in formation water, the ultimate gas recovery factor is significantly higher compared to using nitrogen as an injection agent.

Nuclear Magnetic Resonance Simulation Experiment for a Water Drive Gas Reservoir

The water invasion property and water drive gas displacement efficiency of water drive gas reservoirs are studied under different displacement pressure gradients by using nuclear magnetic resonance (NMR) online detection technology to better guide the scientific exploration of these reservoirs. The breakthrough pressures of the water seal and water lock are also analyzed. The results show that low-permeability gas reservoir water bodies pass through large pores preferentially and then pass through holes and small pores. The remaining gas is mainly distributed in holes and small pores. In contrast, high-permeability gas reservoir water bodies pass through large pores and holes preferentially, and the remaining gas is mainly distributed in large pores and small pores. As the permeability increases, the water drive gas displacement efficiency decreases. As the displacement pressure gradient increases, the displacement efficiency initially increases and then decreases. The breakthrough pressures of the water seal and water lock are highly affected by the permeability. Large permeability results in easy water breakthrough. Variations in the water invasion and water drive gas displacement efficiency are consistent with the variations of the breakthrough pressure and accurately reflect the properties of water drive gas reservoirs.

Production Prediction of Water Drive Gas Reservoir using History Matching

Production Prediction of Water Drive Gas Reservoir using History Matching

Analyzing and forecasting the performance of water drive gas reservoirs

Analyzing and forecasting the performance of water drive gas reservoirs

Integrated Reservoir Study to Optimize Gas Production of Water Drive Gas Reservoir Case Study: Lower Menggala Gas Field

Production optimization in mature field water drive gas reservoir is not easy especially when water already breakthrough in producing wells. An integrated reservoir study is needed to get reliable strategy to optimize production of water drive gas reservoir. This research presents the integrated reservoir study of Lower Menggala (LM) Gas Field which is located Central Sumatera Basin, Riau Province. LM had been produced since 1997, current RF are 55%, which is quite high for water drive gas reservoir. The current gas rate production is about 1.97 MMscfd with high water production around 4250 BWPD, consequently some of wells suffered liquid loading problem This research comprises of well performance analysis, estimate OGIP, aquifer strength of the reservoir by using conventional material balance method and modern production analysis method then conduct dynamic reservoir simulation to identify the best strategy to optimize gas production. Economic analysis also be performed to guide in making decision which scenario will be selected. DST analysis on DC-01 well defined reservoir parameter, boundary and deliverability which are P*= 2520 psia, k= 229 mD, Total skin= 8, detected sealing fault with distance 175 m, and AOF 45 MMscfd. Conventional material balance method gave OGIP 22.7 BScf, aquifer strength 34 B/D/Psi, whereas modern production analysis estimated OGIP 22.35 BScf, aquifer strength 34 B/D/psi. Those two method shows good consistency with OGIP volumetric calculation with discrepancy OGIP value +/- 1%. Six (6) scenario of production optimization has been analyzed, the result shows that work over in two wells and drilling of 1 infill well (case 6) achieve gas recovery factor up to 75.2%, minimal water production and attractive economic result

Numerical simulation of migration characteristics of the two-phase interface in water–gas displacement

The process of water–gas displacement in water–drive gas reservoirs has been always an important research topic. However, knowledge about the flow patterns of water–gas flow under different conditions is insufficient at present. To investigate the variation of the geometry and position of the water–gas interface as well as the water flooding efficiency with time during water–gas displacement, the distribution law of water and gas at the microcosmic scale is simulated and analysed based on the geometric model of a single pore channel abstracted from the parallel tube bundle model and continuous tube bundle model of a porous medium reservoir, with the help of laminar two-phase flow and the level set module of COMSOL Multiphysics. The simulation results show the following: (1) Under the combined effects of the boundary layer effect, interfacial tension and pore diameter changes in water–gas displacement, the shape of the water–gas interface changes from a tongue-shape to a U-shape, during which a series of interface shapes, including a piston shape, finger shape, W-shape and Ω-shape, are observed. In the pore channel, the area of the water phase below the pore channel axial is larger than that above the pore channel axial. (2) The pore-throat ratio has a considerable impact on the shape and location of the water–gas interface as well as the displacement efficiency. When the water–gas displacement is from a small pore-channel to a large one, the displacement efficiency increases as the pore-throat ratio decreases. On the contrary, if the water–gas displacement is from a large pore channel to a small one, the displacement efficiency increases as the pore-throat ratio increases. Numerical simulation can be used to study the shape and location of the water–gas interface as well as the displacement efficiency in pore channels with different scales of diameters.

Application of DOE and metaheuristic bat algorithm for well placement and individual well controls optimization

The design of an optimal gas field development and production management is a complicating task because of influencing various factors on decision-making process. Typical factors include number and type of wells, well locations, and production constraints, economic factors of capital expenditure, operating costs, gas sale price, and different engineering and geological parameters. The situation is further complicated due to uncertainty associated with the nonlinear problem of field development optimization.In this study, first, design of experiment (DOE) techniques including uniform design (UD) and Box-Behnken design (BBD) are used for performance prediction of water drive gas reservoirs. Next, a new metaheuristic bat inspired algorithm (BA) will be applied in optimization process of objective function. Undiscounted net present value (UNPV) is used as an objective function for the determination of optimal number of wells (N), individual well locations (I and J), production rate (Qg), perforation thickness (Hp) and the limit of tubing head pressure (THP) for different average reservoir permeability (KG) and permeability anisotropy (Kv/Kh). In this regard, part of gas reservoir with an active bottom aquifer based on actual data is simulated in order to predict gas recovery factor and cumulative water production data that are necessary for performing production optimization.The results show that reducing gas production rate increases the UNPV. Reducing production rate increases ultimate recovery factor and decreases cumulative water production. However, considering time value of money, it is favorable to produce with high rates and consequently deplete the reservoir over short time scales in order to compensate the reduction of profit.

The material balance equation for fractured vuggy gas reservoirs with bottom water-drive combining stress and gravity effects

Compared with conventional porous-water-drive gas reservoirs, calculating the reserve of a fractured vuggy with water driving is a more difficult and challenging task because of its complex matrix types (matrix, fracture and cavity) and strong rock compressibility. Based on the principles of mass conservation, the material balance equation (MBE) for a fractured vuggy gas reservoir with bottom-water driving is established, and the effects of stress sensitivity and gravity segregation are both considered in the proposed model. The original gas in place (OGIP) and the distribution of the reserve in matrix, fracture and cavity can be determined with the proposed MBE. To test the validity of the model, a depletion test simulating the depleting process of fractured vuggy water-drive gas reservoirs and permeability stress sensitivity experiments with actual full-diameter cores under reservoir conditions are conducted. Then, validation and analysis of the model are compared with the experimental data. It is observed that the water production rate shows a stepped increasing trend instead of a gradually increasing trend during the depletion test. The reserve calculated with the proposed model has the lowest error (1.68%) compared with the experimental data, in which the reserve in the cavity is dominant. Thus, gravity and stress should not be neglected when calculating the reserve of a fractured vuggy gas reservoir with bottom water driving; otherwise, a lower accuracy would be introduced.

Analytical Decline Curve Analysis Model for Water Drive Gas Reservoirs

Production data analysis is a viable tool for reservoir characterization and estimation of initial gas in place (IGIP) and reserves. Several methods are available to analyse production data starting with Arps classical decline curve analysis (DCA) in 1945 all the way to more sophisticated analytical and advanced DCA techniques. Most of these methods are applicable only for single phase flow in porous media. In this paper, we present a simple analytical decline curve analysis (ADCA) model that takes into account the effect of water influx on gas reservoir performance. We introduced the water influx effect into the pseudo-steady state flow equation which enables us to estimate the reservoir pressure and the IGIP for water drive gas reservoirs. The model is based on coupling the material balance equation for gas reservoirs, aquifer models, and the gas flow equation to calculate the well’s production rate versus time. The model can also estimate reservoir pressure, gas saturation, water production rate, and gas production rate with time. When the model is run in history-match mode to match gas and water production, we can estimate the IGIP, well’s productivity index, and aquifer parameters. The model can also be run in prediction mode to predict gas and water production at any conditions of bottom-hole flowing pressure (BHFP) (or surface tubing pressure) and reserves can be calculated. The model was validated with several simulated cases at variable conditions of rate and pressure. The model was then used to perform decline curve analysis in several field cases. This technique is fast and requires minimum input data. The paper will also present the application of this technique to analyse production data and predict reserves for gas wells producing both gas and water.

Nonlinear risk optimization approach to water drive gas reservoir production optimization using DOE and artificial intelligence

The risk of investment in petroleum industry is usually high due to uncertainties associated with performance prediction of hydrocarbon reservoir. To reduce the investment risk, the uncertainties should be estimated accurately. Statistical methods of risk and uncertainty assessment in oil and gas industry have limitations because of underlying principles.This study proposes an improved strategy to reduce uncertainty associated with different engineering and geologic factors. The method optimizes conventional uncertainty assessment methods using evolutionary computing algorithm. In this regard, first; gas recovery factor from water drive gas reservoirs is predicted using five different methods including Box-Behnken design (BBD), Full Factorial design (FFD), Central Composite design (CCD), Uniform design (UD) and relative variation factor (RVF). Next, genetic algorithm (GA) is applied to optimally integrate all conventional uncertainty assessment methods in one equation as a new approach.Part of water drive gas reservoir based on actual data is simulated to extract necessary information in order to be able to quantify the uncertainty of ultimate recovery factor.The effect of average reservoir permeability (KG), permeability anisotropy (Kv/Kh), aquifer size (Vaq), production rate (Qg), perforated thickness (Hp) and lower limit of tubing head pressure (THP) on reservoir performance has been studied.The results show that average reservoir permeability, tubing head pressure, permeability anisotropy, aquifer size, perforated thickness, and production rate have the greatest impact on recovery factor uncertainty, respectively.The results also indicate the higher performance of proposed method over the conventional uncertainty assessment methods to predict the most likely recovery factor. The prediction error of most likely recovery factor by applying GA, BBD, FFD, CCD, UD, and RVF is 0.11, 2.2, 3.15, 2.78, 7.22, and 11.4% respectively.