Drive Gas Reservoirs Research Articles

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.

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.

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.

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

Rigorous framework determining residual gas saturations during spontaneous and forced imbibition using gene expression programming

Aquifer encroachments toward the producing gas zones can substantially decrease the volumetric gas flowrate due to the bypassing of large gas volumes in the porous media. It is well-known that the main parameter monitoring the cumulative gas production is the residual gas saturation; therefore, a complete information about strong aquifer drive gas reservoirs is required relying on both operational and petrophysical parameters. Despite the abundance of studies, attempting to establish comprehensive and adequately precise models for estimating the residual gas saturations is still challenging. In present work, the new method namely, Gene Expression Programming (GEP), was used to propose 9 correlations for force, spontaneous imbibition and the overall waterflood conditions. For this reason, a comprehensive database including 897 residual gas saturation data were adopted from the open source literatures. The variation ranges of the employed dataset include 0.013 to 1 for initial gas saturation, 0.001 to 12950 mD for absolute permeability of rock, 0.008 to 0.494 for porosity (as the input parameters) and 0 to 0.79 for residual gas saturation (as the model output). Numerous types of error analyses such as statistical and visual tools are employed to assess the prediction capability of the new methods developed here as compared with a commonly applied literature model. As a result, it is perceived that the General I, Imbibition I and Force I are the most effective correlations with the root mean square error (RMSE) of 0.09, 0.06 and 0.14, consecutively. The results of the literature model are less efficient than our newly suggested methods. Moreover, the so-called technique of sensitivity analysis revealed that the porosity and permeability have insignificant impacts on predicting the residual gas saturation in the case of spontaneous imbibition. To end with, the results of this study can be the good nominees for fast, accurate and inexpensive estimation of the residual gas saturation especially during reservoir engineering simulation and calculation at the time in which the whole information may not be available to the researches.

Modeling Aquifer Flow Behavior in Low-Dip Edge-Water Drive Gas Reservoirs

Water encroachment from aquifers into hydrocarbon reservoirs plays a crucial role in water production and, consequently, in prediction of hydrocarbon field performance. In this regard, several analytical and numerical models have been introduced to calculate water influx. While many studies have been conducted on water influx calculations in hydrocarbon reservoirs, the authors were unable to find any previous study describing aquifer behavior in relation to low-dip reservoirs. In this study, we investigated aquifer behavior in this specific reservoir type from two perspectives: First, water encroachment mechanisms from an aquifer into a low-dip reservoir were assessed, using a numerical gridded approach. Second, we evaluated the validity of analytical and numerical models used in commercial reservoir simulators for low-dip, edge-water drive (LDEWD) reservoirs. We applied the findings of this study to a LDEWD in a heterogeneous carbonate gas reservoir in the Middle East. This was the first study to identify that the major water influx was from the outer corner of the reservoir in the low-dip, edge-water aquifer. We have referred to this phenomenon as outer corner water encroachment (OCWE). We also showed that commonly available analytical and numerical models could not capture either a precise water movement profile or the water influx volume for LDEWD aquifers. The simulation results from prediction models used with actual field data showed that lateral water movement from the outer corner of the reservoir (OCWE movement) was the main contributor to water encroachment and production—and that the vertical water coning phenomenon was not significant in heterogeneous carbonate reservoirs.

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

A NEW MODEL PREDICTING WATER BREAKTHROUGH TIME IN BOTTOM-WATER DRIVE GAS RESERVOIR BASED ON CAPILLARY PRESSURE AND BUCKLEY-LEVERETT EQUATION

A NEW MODEL PREDICTING WATER BREAKTHROUGH TIME IN BOTTOM-WATER DRIVE GAS RESERVOIR BASED ON CAPILLARY PRESSURE AND BUCKLEY-LEVERETT EQUATION

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.

Inflow Performance Relationship Correlation for Solution Gas-Drive Reservoirs Using Non-Parametric Regression Technique

Background:The Inflow Performance Relationship (IPR) describes the behavior of flow rate with flowing pressure, which is an important tool in understanding the well productivity. Different correlations to model this behavior can be classified into empirically-derived and analytically-derived correlations. The empirically-derived are those derived from field or simulation data. The analytically-derived are those derived from basic principle of mass balance that describes multiphase flow within the reservoir. The empirical correlations suffer from the limited ranges of data used in its generation and they are not function of reservoir rock and fluid data that vary per each reservoir. The analytical correlations suffer from the difficulty of obtaining their input data for its application.Objectives:In this work, the effects of wide range of rock and fluid properties on IPR for solution gas-drive reservoirs were studied using 3D radial single well simulation models to generate a general IPR correlation that functions of the highly sensitive rock and fluid data.Methodology:More than 500 combinations of rock and fluid properties were used to generate different IPRs. Non-linear regression was used to get one distinct parameter representing each IPR. Then a non-parametric regression was used to generate the general IPR correlation. The generated IPR correlation was tested on nine synthetic and three field cases.Results & Conclusion:The results showed the high application range of the proposed correlation compared to others that failed to predict the IPR. Moreover, the proposed correlation has an advantage that it is explicitly function of rock and fluid properties that vary per each reservoir.

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.

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.

A Novel Analytical Curve for Forecasting and Monitoring Gasflood Performance

With the increasing proportion of gas cap & artificial gas injection reservoirs, production performance monitoring and evaluation of gas-drive reservoir are becoming more and more important. However, there is no efficient method to forecast the production performance of gas-drive reservoir. In this paper, the analysis starts from the statistics of oil/gas relative permeability data of cores experiments. Based on fundamental principles of segregated flow and material balance, a new analytical curve of gasflood was developed to analyze the production performance. We applied the novel analytical curve to the production data from 23 gas-drive reservoirs at home and abroad and found a better power function relationship between dynamic reserves (N) and the slope (B) as foreseen by the analytical curve. It has been shown that the slope of the new curve represents dynamic reserves value; the smaller the slope value is, the more dynamic reserves are. Furthermore, by introducing the economic limit gas-oil ratio and control conditions which include initial and boundary conditions, a chart of dimensionless fractional flow of gas vs. recovery percent of OOIP is established to evaluate oilfield development rapidly and intuitively. Finally, many examples of application confirmed strongly that the new analytical curve used in gas-drive reservoirs is practical and effective, which broadens the scope of gas-drive oilfield research.