Gas Reservoir Model Research Articles

Effect of Stress-Sensitive Permeability and Porosity on Production Performance in Water-Soluble Gas Reservoirs

Abstract Water-soluble gas reservoirs have the characteristics of high temperature and high pressure (HTHP) and experience obvious pressure-sensitive effects during the production process. Therefore, the influences of formation water and dissolved natural gas in formation water on water-soluble gas reservoirs are different from conventional gas reservoirs. In view of this, this work first carried out a stress sensitivity test with irreducible water and variable internal pressure at high temperature for a water-soluble gas reservoir, showing that permeability loss ratio and effective stress have an exponential relationship, a result basically consistent with conventional tests. However, the stress sensitivity test result with irreducible water was greater than the stress sensitivity test result without irreducible water; porosity decreased slightly with increasing confining pressure, and the total decrease ratio was less than 5.2%, with an average of 3.01%. Second, a high-pressure, high-temperature, nuclear magnetic resonance (NMR) online detection system was introduced to detect the pore signal of core samples under different effective stress states, and pore compression and deformation characteristics were evaluated. Results show large pores to have been compressed slightly more than small pores, pores to be significantly compressed in the initial stage, and the greater the increase in effective stress, the more obvious the compression. Third, the occurrence and characteristic changes of irreducible water in the process of rock compression were detected by the NMR online system, indicating irreducible water to be difficult to migrate through compression in water-soluble gas reservoirs under slight compression of rock and pore structure and the occurrence and characteristics of irreducible water to have not changed significantly. Finally, by establishing a theoretical model of water-soluble gas reservoirs to simulate the water breakthrough of gas wells under stress sensitivity conditions, this work shows that when stress sensitivity exists, gas-well water breakthrough time is earlier and production is diminished.

Permeability prediction in tight gas reservoirs based on pore structure characteristics: A case study from South Western Iran

Abstract Porosity, pore structure characteristics, and permeability are among the key petrophysical properties of shale gas resources. Accurate characterization of these parameters in the unconventional gas shale systems has been proved to be challenging due to the uniqueness of the pore structures, mineral compositions, tightness, and pores hosted in the organic matter. In this study, the porosity, pore structure characteristics, and permeability of cored samples from the Garau shale formation located in the southwestern part of Iran were evaluated using a combination of laboratory methods. Multiple linear regression analyses were then utilized to develop empirical relationships between helium permeability values, porosity, and pore throat radii. Results showed that the best permeability predictors for the examined samples could be developed using the pore throat radius that corresponds to a mercury saturation of 55% and porosity. This approach helps develop a permeability prediction model for tight shale gas reservoirs based on pore structure characteristics, reducing cost and time.

A New Prediction Model of Water Breakthrough Time of Horizontal Well in Inclined Edge-Water Low Permeability Gas Reservoir

At present, the existing water breakthrough time models in edge-water gas reservoirs are mainly based on the vertical well scheme and ignore the impact of the formation dip angle and non-Darcy flow effect, thus resulting in some differences between the predicted and actual measured data. To improve the accuracy of prediction, we have considered the effect of gravity caused by the dip angle in the edge-water gas reservoir. The established mathematical model of a low permeability edge-water gas reservoir is based on the theory of gas-water two-phase seepage. The prediction model of water breakthrough time in a horizontal well considers the influence of the formation dip angle, starting pressure gradient, and non-Darcy flow effect. The prediction model sensitivity analysis has been carried out. The results show that the predicted time of the new model is closer to the actual water breakthrough time in the gas reservoir than that of the existing models. The sensitivity analysis results show that the water breakthrough time decreases with increase in the gas well production, and increases with increase in formation dip angle, horizontal well length, and original distance between the gas-water interface and the well bottom. For the same horizontal well length, the water breakthrough time calculated considering the non-Darcy flow effect is shorter than the time calculated without considering the non-Darcy flow effect. The research results provide the necessary background for accurate prediction of the water breakthrough time in edge-water gas reservoirs.

Adaptation of the material balance of a gas deposit

The aim of the researching is to study the application of the material balance method with modern technologies to create a useful gas reservoir model with water influx. The basic equations of material balance are analyzed taking into account the Mendeleev-Clapeyron law for gases. The analysis was performed taking into account the water influx component according to Fetkovich's equations. The paper highlights the problems of identifying the parameters of the material balance model as material balance model doesn’t include the geological structure of deposits. The calculation was done by material balance models created on Mathcad and VBA Excel. The analysis and examples given in the article testify to the expediency of applying the method of material balance with VBA Excel to clarify gas reserves, including those with a water-driven or mixed mode of development and obtain an adequate model of the reservoir.

Prediction model of water-soluble gas content in a high-pressure and high-temperature water-soluble gas reservoir

In high-temperature, high-pressure (HTHP), water-soluble gas reservoirs, a significant amount of natural gas is dissolved in the formation water. During development, with changing reservoir pressure, the natural gas in the formation water will be released. The released natural gas will carry the formation water to form gas-liquid two-phase flow into the porous media of the gas reservoir, which results in premature water breakthrough, thus changing the law of formation water invasion. In order to determine the influence of water-soluble gas on formation water invasion, it is important to study the water-soluble gas content of water-soluble gas reservoirs. Based on experimentation and existing modeling, a prediction model was established for water-soluble gas content in HTHP water-soluble gas reservoirs, and the influence of water-soluble gas content on water invasion was studied. From the results, the following conclusions can be drawn. (a) The content of water-soluble gas increases with increasing pressure, first decreasing and then increasing with increasing temperature. (b) In addition to temperature and pressure, the factors affecting the content of water-soluble gas include the gas components and the mineralization degree of formation water. (c) The existing prediction model has the problems of large error and inconsistency with the measured value, (average error being 33.92%), especially lacking consideration of how changing carbon dioxide content in the gas composition affects the water-soluble gas content. (d) Considering the influences of temperature, pressure, gas components, and formation water mineralization on the prediction model of water-soluble gas reservoirs, the calculation results of the model are more in line with the actual circumstances of gas reservoirs, with the average error being 6.81% and the accuracy of water-soluble gas content prediction being increased five times. (e) Through case analysis, it is shown that the release of water-soluble gas has a great impact on the water breakthrough law of gas wells. Considering the water-soluble gas, the water breakthrough time of gas wells is relatively early. Results show that the water-soluble gas content prediction model for HTHP water-soluble gas reservoirs can predict the water-soluble gas content of water-soluble gas reservoirs more accurately, laying a foundation for understanding the water invasion law of water-soluble gas reservoir development and developing such a gas reservoir efficiently.

Pressure Performance of Highly Deviated Well in Low Permeability Carbonate Gas Reservoir Using a Composite Model

It is commonly believed that matrix and natural fractures randomly distribute in carbonate gas reservoirs. In order to increase the effective connected area to the storage space as much as possible, highly deviated wells are widely used for development. Although there have been some studies on the composite model for highly deviated wells, they have not considered the effects of stress sensitivity and threshold pressure gradient in a dual-porosity gas reservoir. In this paper, a semi-analytical composite model for low permeability carbonate gas reservoir was established to study the effect of non-Darcy flow. By employing source function, Fourier transform and the perturbation method, the pressure performance and typical well test curves were obtained. Eight flow regimes were identified, and their characteristics were discussed. As a result, it can be concluded that the effects of stress sensitivity and threshold pressure gradient would make pseudo-pressure and derivative curves rise, which is the characteristic of non-Darcy flow to determine whether there is stress sensitivity or threshold pressure gradient.

Study on a New Rock Fracability Evaluation Model of Shale Gas Reservoir

Shale gas is an important unconventional energy resource that needs large-scale fracturing to form industrial deliverability. The evaluation of reservoir fracability plays a key role in the optimization of the sweet spot, the design of multistage fracturing, and the prediction of economic benefit. Based on volumetric fracturing, the study proceeded from the fracture complexity of the fractured core, and the bursting pressure experiment technology using the constant strain rate method was established. After the core has fractured, the fracture morphology was extracted and the fracture parameters including fracture area ratio and fracture declination dispersion were calculated to construct the fracture complexity of the pressed core. Combined with the core strength, the fracability index of the core was determined to evaluate the reservoir fracability. This method can represent not only the fracturing effect but also the fracturing difficulty. Compared with the monitoring data of hydrofracture-induced microseism of the sample well, the core fracturing index was found to be in good agreement with the actual fracturing effect. This method is more reasonable than the traditional brittleness index method and rock mechanics parameter method.

Numerical Simulation of the Non-Darcy Flow Based on Random Fractal Micronetwork Model for Low Permeability Sandstone Gas Reservoirs

Darcy’s law is not suit for describing high velocity flow in the near wellbore region of gas reservoirs. The non-Darcy coefficient β of the Forchheimer’s equation is a main parameter for the evaluation of seepage capacity in gas reservoirs. The paper presented a new method to calculate β by performing gas and con-water flow simulations with random 3D micropore network model. Firstly, a network model is established by random fractal method. Secondly, based on the network simulation method of non-Darcy flow in the literature of Thauvin and Mohanty, a modified model is developed to describe gas non-Darcy flow with irreducible water in the porous medium. The model was verified by our experimental measurements. Then, we investigated the influence of different factors on the non-Darcy coefficient, including micropore structure (pore radius and fractal dimension), irreducible water saturation ( S wi ), tortuosity, and other reservoir characteristics. The simulation results showed that the value of the non-Darcy coefficient decreases with the increase in all: the average pore radius, fractal dimension, irreducible water saturation, and tortuosity. The non-Darcy coefficients obtained by the fractal method of microparameters are estimated more precisely than the conventional methods. The method provides theoretical support for the productivity prediction of non-Darcy flow in gas reservoirs.

Investigation on multi-scale pore seepage model of shale gas reservoir considering diffusion and slippage effect

Shale gas reservoirs which are usually heterogeneous ones have a multiplicity mode of occurrence. A comprehensive understanding of the complex migration mechanism is prerequisite to fully comprehend the reservoir seepage. In this paper, the gas flow types are classified based on Knudsen number; the aperture distribution is introduced as the weight coefficient of the comprehensive constitutive equation. Then, the multi-scale pore time fractional order seepage model considering the influence of real gas effect, diffusion effect and slippage effect, is established. The reliability of the new model is verified using the existing experimental data presented in previous literature. Our results show that the new model can accurately capture all the mechanisms of gas migration, and well characterize the influence of structure heterogeneity and real gas effect. Moreover, analysis results also indicate the diffusion effect and slippage effect play a critical role in the multi-scale seepage happened in shale gas reservoir. In conclusion, the new model which considers the real gas effect, diffusion effect and slippage effect, can accurately calculate the apparent permeability, which is a key issue in the production dynamic analysis and productivity prediction of shale gas.

Special features of tight gas reserves determination

Special features of tight gas reserves determination, based on material balance method, were characterized, since reliability of initial hydrocarbons in place determination plays important role in future field development planning, particularly on recovery rate, wells to be drilled, capital expenditures, surface facilities etc. Using the synthetic 3D model of gas reservoir, different development scenarios were evaluated according to the different spatial distribution patterns of petrophysical properties within the reservoir. Analyzing the obtained results, the authors fully confirmed an assumption made, that significant heterogeneity of reservoir properties makes a great impact on the shape of pseudo reservoir pressure curve vs cumulative gas produced and introduces significant errors into determination of initial gas in place. At the late stages of the development, the slope of P/z straight line changes, and this allows determination of much greater reserves’ volumes. Usage of pseudo reservoir pressure vs cumulative produced gas for determination of drained reserves in tight gas formation is especially risky, because the production data can indicate the true volumes of gas in place, only after the majority of the gas been produced. In most cases, the development period to acquire necessary data for correct volumes in place estimation exceeds the planning period. This factor introduces the significant error into future field development during the planning phase. Due to that, at the initial development stages, the error in drained volumes estimation can account for 50% out of true initial volumes in place. Based on conducted research, the potential error evaluation for tight gas reservoirs initial gas in place determination with decline pressure material balance method was performed. According to the results of computer simulation, the error can account for 25% from true initial gas in place in simulation model. This error significantly excesses the acceptable limits and can lead to wrong decisions in development planning

Shale gas production forecasting is an ill-posed inverse problem and requires regularization

Abstract Decline curve analysis (DCA)—the extrapolation of a production curve model fitted to a well’s past production—remains the standard approach for forecasting unconventional oil and gas production. A scaling curve based on a fractured shale gas reservoir model was recently proposed as a way of connecting this approach with underlying physics but as this paper shows, it actually generates worse predictions than the traditional non-physical modified Arps curve. DCA is fundamentally an ill-posed inverse problem with the defining characteristic of model sloppiness, or parameter correlation. Today’s unconventional resource forecasts can be substantially improved by using information from offset wells to reduce ill-posedness through Tikhonov regularization. This versatile approach nearly matches a deep neural network approach introduced here, which has practical limitations but offers a model-neutral benchmark of achievable extrapolation accuracy. There is a natural connection between regularization and a Bayesian formulation which is also highlighted. This paper evaluates long-term forecasting accuracy for these techniques using historic production data from 4457 Barnett shale wells, and reveals that the overlooked step of regularization is more critical than choice of model.

A hybrid model for the combined impact of non-Darcy flow, stimulated matrix permeability, and anomalous diffusion flow in the unconventional reservoirs

Abstract A hybrid model for unconventional gas reservoirs that couples three different parameters is presented in this paper. The first is the anomalous diffusion in a fractal porous media. The second is the stimulated or induced matrix permeability in the stimulated reservoir volume (SRV). The third is the non-Darcy flow permeability in the hydraulic fractures. This model is generated from the multi-linear flow model for fractal reservoirs controlled by diffusive flow mechanism with adjustment for fluid flux through hydraulic fracture face considering minimum fracture relative permeability (kmr) and non-Darcy flow Number (FND). Pressure distributions, flow regimes, and reservoir performances have been investigated for three types of unconventional reservoirs. The first is formations with homogenous matrix permeability where petrophysical properties of stimulated and un-stimulated reservoir volume are the same. The second is fractal reservoirs with different petrophysical properties in the two volumes without considering normal or classic diffusion mechanism. The third is the fractal reservoirs where anomalous diffusive flow mechanism dominates fluid flow. A set of comparisons has been generated between the three types for better understand the impact of non-Darcy flow permeability and stimulated matrix permeability on reservoir performance under normal and anomalous diffusion flow mechanisms. The outcomes of this study are: (1) Generating a new analytical model that describes pressure distribution in fractal unconventional reservoirs and couples non-Darcy flow, stimulated or induced matrix permeability with the anomalous diffusion in porous media. (2) Understanding the impact of these different parameters on reservoir performance. (3) Developing different models for all types of flow regimes that are expected to be observed during the entire production life. (4) Comparing the productivity index of reservoirs: having homogeneous matrix permeability, fractal with normal diffusion, and fractal with anomalous diffusion. The most interesting points in this study are: (1) Minimum fracture relative permeability (kmr) significantly enhances the productivity index by eliminating the impact of non-Darcy flow while non-Darcy flow number (FND) works conversely (2) Increasing stimulated matrix permeability enhances reservoir performance (3) The impact of non-Darcy flow permeability of hydraulic fractures is seen at early and intermediate production time where transient flow is dominant. (4) Two different trends are recognized for the impact of anomalous diffusion flow: the first is a positive impact on the transient flow period and the second is negative in the pseudo-steady state flow.

Shale gas reservoir modeling and production evaluation considering complex gas transport mechanisms and dispersed distribution of kerogen

Stimulated shale reservoirs consist of kerogen, inorganic matter, secondary and hydraulic fractures. The dispersed distribution of kerogen within matrices and complex gas flow mechanisms make production evaluation challenging. Here we establish an analytical method that addresses kerogen-inorganic matter gas transfer, dispersed kerogen distribution, and complex gas flow mechanisms to facilitate evaluating gas production. The matrix element is defined as a kerogen core with an exterior inorganic sphere. Unlike most previous models, we merely use boundary conditions to describe kerogen-inorganic matter gas transfer without the instantaneous kerogen gas source term. It is closer to real inter-porosity flow conditions between kerogen and inorganic matter. Knudsen diffusion, surface diffusion, adsorption/desorption, and slip corrected flow are involved in matrix gas flow. Matrix-fracture coupling is realized by using a seven-region linear flow model. The model is verified against a published model and field data. Results reveal that inorganic matrices serve as a major gas source especially at early times. Kerogen provides limited contributions to production even under a pseudo-steady state. Kerogen properties’ influence starts from the late matrix-fracture inter-porosity flow regime, while inorganic matter properties control almost all flow regimes except the early-mid time fracture linear flow regime. The contribution of different linear flow regions is also documented.

Effect of Complex Natural Fractures on Economic Well Spacing Optimization in Shale Gas Reservoir with Gas-Water Two-Phase Flow

At present, investigation of the effects of natural fractures on optimal well spacing of shale gas reservoirs from an economic perspective has been lacking. Traditional frameworks of fracture characterization, such as local grid refinement, make it unfeasible and inaccurate to study these effects of high-density natural fractures with complex geometries on well spacing. In this study, the non-intrusive EDFM (embedded discrete fracture model) method was presented to characterize fractures fast and accurately. The non-intrusiveness of EDFM removed the necessity of accessing the codes behind reservoir simulators, which meant it could simply create associated keywords that would correspondingly modify these fracture properties in separate files without information regarding the source codes. By implementing this powerful technology, a field-scale shale gas reservoir model was set up, including two-phase flow. The effective properties of hydraulic fractures were determined from the history matching process, and the results were entered into the well spacing optimization workflow. Different scenarios of natural fracture (NF) distributions and well spacing were designed, and the final economic analysis for each case was explored based on simulated productions. As a result, one of the findings of this study was that optimal well spacing tended to increase if more natural fractures were presented in the reservoir.

A new numerical production well model for the low-permeability gas reservoir

In the development of low permeability gas reservoirs, capillary end effect has a significant impact on the flow near the production well, and physical quantities near the production well all change dramatically, which may reduce the oil and gas production. Traditional well model cannot describe this phenomenon. In this paper, based upon the analytical solution of one dimensional radial flow, an alternative numerical well model for low permeability gas reservoir considering the end effect is constructed. The numerical results show that the gas and water productions can be predicted accurately at different grid scales using the proposed well model. In contrast, the Peaceman well model for multi-phase only can get the accurate results when the grid is enough subdivided.

Study on Gas Recovery Program Optimization in Deep Water Gas Reservoir

LS-17 gas field is China’s first self-operated deep-water gas field in the south China sea. Located in the southeast of hainan island, the gas field has a depth of 1220-1560 meters. According to the gas reservoir characteristics of ls-17 gas field, the gas reservoir model and numerical model of water control process of ls-17 gas field are established, the productivity of existing wellhead gas reservoir is predicted, the gas production plan of gas reservoir is optimized, and the optimal solution of recovery rate of compressed gas reservoir is given under different system changes, different processes and different development modes. In this paper, the gas production rate and recovery rate at different gas production rates are predicted, and the gas recovery rate is optimized. The development method of intermittent gas production is put forward, and the parameters of intermittent gas production are not optimized. The deep water gas reservoir is characterized by high energy and serious water intrusion. This paper compares and evaluates the recovery efficiency under different water control technologies, and proposes a method for selecting water control technology measures in the process of gas reservoir development. The research ideas and methods in this paper effectively support the scientific decision-making of gas recovery program in LS-17 gas field and have certain guiding significance for the development of deepwater gas reservoirs in the south China sea.

Combining natural gas recovery and CO2-based geothermal energy extraction for electric power generation

We investigate the potential for extracting heat from produced natural gas and utilizing supercritical carbon dioxide (CO2) as a working fluid for the dual purpose of enhancing gas recovery (EGR) and extracting geothermal energy (CO2-Plume Geothermal – CPG) from deep natural gas reservoirs for electric power generation, while ultimately storing all of the subsurface-injected CO2. Thus, the approach constitutes a CO2 capture double-utilization and storage (CCUUS) system. The synergies achieved by the above combinations include shared infrastructure and subsurface working fluid. We integrate the reservoir processes with the wellbore and surface power-generation systems such that the combined system’s power output can be optimized. Using the subsurface fluid flow and heat transport simulation code TOUGH2, coupled to a wellbore heat-transfer model, we set up an anticlinal natural gas reservoir model and assess the technical feasibility of the proposed system. The simulations show that the injection of CO2 for natural gas recovery and for the establishment of a CO2 plume (necessary for CPG) can be conveniently combined. During the CPG stage, following EGR, a CO2-circulation mass flowrate of 110 kg/s results in a maximum net power output of 2 MWe for this initial, conceptual, small system, which is scalable. After a decade, the net power decreases when thermal breakthrough occurs at the production wells. The results confirm that the combined system can improve the gas field’s overall energy production, enable CO2 sequestration, and extend the useful lifetime of the gas field. Hence, deep (partially depleted) natural gas reservoirs appear to constitute ideal sites for the deployment of not only geologic CO2 storage but also CPG.

Analysis on the effect of different fracture geometries on the productivity of tight gas reservoirs

Tight gas reservoirs are unconventional reservoir assets which have been the focus of major research in the petroleum industry owing to the global decline in conventional reservoirs. They are widely unlocked by creating hydraulic fractures in the formation to increase the flow capacity and productivity. The objective of this paper is to analyze different fracture geometries and their effect on tight gas production. The reservoir simulation model of the tight gas reservoir has been built with single porosity approach. A single vertical well with a single stage fracture has been used in the model to predict the behavior of fracture geometry. The major parameters of fracture geometry studied are fracture half-length, fracture width, and fracture height. Four sensitivities are run over different fracture geometry that is constant height and constant width, constant height and changing width, changing height and constant width, and changing height and changing width, while increasing the fracture half-length from 100 ft to 500 ft in each case. Sensitivity analysis exhibited that keeping the hydraulic fracture at constant height and constant width while increasing the fracture half-length resulted in enhanced tight gas productivity i.e. 11.63%, 14.14%, 16.06%, 17.48%, and 18.89% at hydraulic fracture half-lengths of 100 ft, 200 ft, 300 ft, 400 ft, and 500 ft, respectively, compared to other types of fracture geometry.

Production decline analysis of shale gas based on a probability density distribution function

Abstract Production decline analysis is a simple and efficient method to forecast production dynamics of shale gas. The traditional Arps decline model is also widely used in the production decline analysis of shale gas, but an obvious error is often generated. Based on the Weibull and χ2 probability density distribution function, the monotonic decreasing production prediction equations of shale gas are established. It is deduced that recently, the widely used Duong model is essentially a Weibull probability density distribution model. Decline analysis results of production data from actual shale gas well and numerical simulations indicate that the fitting results of the Weibull (Duong) model and χ2 distribution model are better than the Arps model whose deviation of early data is large. For a shale gas reservoir with very low permeability, pressure conformance area is small and it is obviously influenced by fractures. Early shale gas production rate mainly contributed to by fractures declines quickly and the later production rate mainly contributed to by the matrix declines slowly over time. The production decline curve has obvious long-tail distribution characteristics and it is a better fit to the data with a χ2 distribution model. As for the increase of permeability, the fitting accuracy of the Weibull (Duong) model gradually becomes better than the χ2 distribution model. Research results provide theoretical guidance for choosing a reasonable production decline model of a shale gas reservoir with a different permeability.

A productivity prediction method for condensate gas reservoir

At present, multiphase flow productivity calculation requires many parameters, and most of them only consider oil and gas two-phase flow, which is complicated and limited. Therefore, a reasonable productivity formula of condensate gas reservoir with producing water is needed. The three-zone model of condensate gas reservoirs is generally applied to the physical model for inferring productivity. On this basis, an improved model is established, which includes that different seepage characteristics are considered for different zones. Moreover, the effects of inclined angle and water production on gas wells are regarded as pseudo-skin factors and additional-skin factors. In addition, Zone I considers the effects of high-speed nonDarcy effect(HSND), starting pressure gradient, stress sensitivity, inclined angle and water production; Zone II is the same way excepting starting pressure gradient and stress sensitivity ; Zone III only considers the effects of inclined angle and water production. As a result, a productivity equation with multiple factors for condensate gas wells is established. Through analysing cases and influences in H gas reservoir X1 well, the HSND, starting pressure gradient, stress sensitivity and water production have a negative impact on gas well productivity, but the inclined angle is opposite. Founded that the starting pressure gradient impacts on productivity is less than the HSND because of the limited radius of Zone I; the impact of the HSND on productivity increases with the decreasing of bottom hole pressure; the impact of water production on gas well productivity is much higher. When the angle is over 60°, the effect of gas