Interlayer Crossflow Research Articles

Super-long gravity heat pipe geothermal space heating system: A practical case in Taiyuan, China

Using super-long gravity heat pipes (SLGHPs) to exploit deep-earth geothermal energy has indicated its technical superiority and viability; yet there is no practical application so far. The present work reports an SLGHP geothermal space heating system constructed in Taiyuan, China, which has two SLGHPs (2020 m and 2180 m long, respectively) in combination with a single heat pump. The two wells are located only ∼30 m apart, and the well-log temperature at 2000 m depth is around 63 °C for both. Temperatures measured by the optical fiber arranged along the SLGHP outer wall show remarkable uniformity, indicating the good performance of SLGHPs. Testing with the SLGHP system finds that the slightly longer SLGHP extracts 70 % more heat than the other one. Analyses reveal that the heat transfer in the geothermal formations surrounding the shorter SLGHP approximately follows the heat conduction regime while the convection of groundwater contributes less; the high yield of the slightly longer SLGHP is due to an interesting downhole heat transfer enhancement mechanism arising from the interlayer crossflow of groundwater. Further, a numerical model is developed to predict the SLGHP geothermal system's performance in 120-days’ operation. It is found that this system can output 1 MW of heat, sufficing space heating of ∼25,000 m2 buildings. The simulated 20-years’ operation indicates the thermal output degradation is 20.4 % for the shorter SLGHP, whereas it is only 6.8 % for the slightly longer SLGHP; the downhole groundwater crossflow lowers the SLGHP system degradation rate.

Characteristics and Controlling Factors of Fluid Interlayer Crossflow through Fractures in Coal Measure Gas Reservoirs: Implication for Enhancing Production

Characteristics and Controlling Factors of Fluid Interlayer Crossflow through Fractures in Coal Measure Gas Reservoirs: Implication for Enhancing Production

Pressure Analysis of Onshore and Offshore Shale Gas Reservoirs under Constant-Rate Condition Considering Thin Sandstone Layer and Interlayer Cross-Flow

The extraction of shale gas from onshore and offshore shale gas reservoirs will play an important role in meeting China’s future energy needs, which will not only help alleviate the energy crisis but also contribute to climate change mitigation. As for the target shale formation enriched by thin sandstone layers in typical basins, an analytical calculation method is proposed to perform pressure analysis for multi-layer shale gas reservoirs considering the adsorption–desorption characteristics of shale layer and the interlayer cross-flow. Firstly, the changes in storage capacity and flow resistance are obtained by using the distance of investigation equation. According to the electrical analogy, the equivalent total storage capacity and flow resistance can be calculated considering the sandstone-shale crossflow. Because production from one time step to the other causes depletion of the storage capacity, the reservoir pressure in different time steps can be calculated based on the material balance equation. Numerical models have been constructed based on three typical reservoir lithology combinations (sandstone-shale, shale-sandstone-shale and sandstone-shale-sandstone) to validate the accuracy of the proposed analytical calculation method. Furthermore, three important factors (porosity, the ratio of horizontal/vertical permeability (kh/kv) and the layer thickness) have been selected for the sensitivity analysis to verify the stability. The comparative results indicate that the proposed analytical calculation method is suitable for pressure analysis in shale gas reservoirs containing thin sandstone layers. It will provide theoretical support for the further enhancement of the production of this type of gas reservoirs.

Numerical investigation of production characteristics and interlayer interference during co-production of natural gas hydrate and shallow gas reservoir

The coexistent system of natural gas hydrate and shallow gas (NGH-SG) enhances stability compared to single resource reservoirs, rendering it a promising target for co-production and commercial exploitation. In this study, we established a reservoir model of the NGH-SG system based on actual geological conditions. Subsequently, a long-term production simulation was performed to contrast the production behaviors of three exploitation methods: co-production of NGH-SG (CP), single production of hydrate-bearing layer (SP-HBL), and single production of shallow gas layer (SP-SGL). The study revealed that the presence of free gas in SGL can significantly increase the overall gas production capacity, with SGL contributing over 85% of the total gas production during the entire co-production period. On the 5000th day, the cumulative gas production of CP exceeded that of SP-SGL by 1.07 times and surpassed SP-HBL by 9.60 times. Furthermore, the study extensively investigated the impact of interlayer permeability on production behaviors. Lower interlayer permeability was found to be more conducive to releasing the natural gas production capacity from the reservoir. Notably, the phenomenon of interlayer interference should be carefully considered during CP. The influence degree of interlayer interference during CP becomes increasingly pronounced with increasing interlayer permeability. Fundamental contributors to interlayer interference encompass heat transfer, pressure diffusion, and interlayer cross-flow. As interlayer permeability rises, mass transfer between the layers intensifies, thus promoting pressure diffusion. Interlayer pressure difference and permeability are critical factors that affect interlayer cross-flow. For NGH-SG reservoirs with higher interlayer permeability, the advantages of CP are more obvious during the early production period. The implementation of the findings of this study may improve production efficiency and contribute to the development of effective management strategies for offshore NGH-SG reservoirs.

Impact of Crossflow and Two-Phase Flow on Gas Production from Stacked Deposits

The gas production from stacked gas deposits with coalbed, shale, and tight sandstone reservoirs in the coal measure is an effective new technology to enhance per well gas production. However, previously developed numerical models for stacked gas deposits usually target one or two reservoir types. The contribution and impact mechanism of crossflow and two-phase flow on gas production from stacked gas deposits are unclear for the stacked gas deposits with coalbed, shale, and tight sandstone reservoirs in the coal measure. This paper develops a numerical simulation model for the gas production from stacked deposits with shale, coalbed, and tight sandstone reservoirs. This numerical simulation model considers the two-phase flow, gas diffusion in different porosity, pore deformation, and interlayer crossflow. After verification with available data from the literature, this numerical simulation model is used to explore the effects of crossflow across interlayers and two-phase flow on gas transport and production efficiency. The simulation results show that the main sources of gas production from stacked deposits are shale and coalbed reservoirs. The gas in these two reservoirs can be rapidly transported to the wellbore through the tight sandstone reservoir. The gas production from stacked deposits will be underestimated without the interlayer crossflow and overestimated if the two-phase flow is ignored. The gas production efficiency can be effectively improved through the enhancement of the crossflow rate at the interlayer and the decrease of the water saturation in the reservoir.

Experimental Investigation of Reservoir Fluid Interlayer Crossflow Through Fracture During the Drainage Stage of Coal Measure Gas Well

Experimental Investigation of Reservoir Fluid Interlayer Crossflow Through Fracture During the Drainage Stage of Coal Measure Gas Well

Analytical Modeling of Multistage Hydraulically Fractured Horizontal Wells Producing in Multilayered Reservoirs with Inter-Layer Pure-Planar Crossflow Using Source/Sink Function Method

This study presents a comprehensive analytical modeling technology to model transient behaviors of multilayered reservoirs with inter-layer pure-planar crossflow induced by multi-stage hydraulically fractured horizontal well (MHFHW). The objective of this study is to develop an analytical model for multilayered reservoirs in conjunction with complex MHFHW and to achieve not only accurate and efficient computation, but also well-organized solutions expressed in a systematically integrated manner. The consideration of inter-layer crossflow across adjacent layers sets up the foundation for successful modeling of multilayered reservoirs. Source/sink function method (SSFM) is applied to describe fluid flow. Unsteady-state pressure or production rate solutions of MHFHW with the advantages of fast computation, accurate, and stable solutions are achieved. Comparative and consistent outcomes generated by this work and widely applied industry software have largely enhanced our technical confidence. More importantly, innovatively defined modified dimensionless terms that integrate systematic well-reservoir geometry information, as well as rock/fluid properties of each layer, have been newly applied to regulate the new modified dimensionless rate decline curve. This new technique sheds light on the reservoir characterization practice for complicated reservoir systems. Theoretical results in terms of transient pressure and rate were generated by the proposed multilayered model (SSFM-ML) for five scenarios of general concern, under various reservoir and well parameters, which were examined and discussed to demonstrate technical robustness. Not only does this study give solutions to the targeted multiple layered reservoirs, but it also provides insights into modeling three-dimensional fluid flow in heterogeneous reservoir with complex well configurations. It is recommended that future research should be conducted for more complicated two- and three-dimensional reservoirs, using the similar strategy of developing new type curves through adopting other new forms of modified dimensionless rate and time terms.

The experimental study on integrated hydraulic fracturing of coal measures gas reservoirs

Coal measures are rich in coalbed methane, shale gas and tight sandstone gas, and the three gases co-exploration has become a potentially promising technology in China. During the process of integrated hydraulic fracturing of three gas formations in coal measures, interlayer contradiction occurs due to the formation heterogeneity, which is the key to restricting the application of this technology. In this paper, an experimental device has been designed to study the influencing factors for integrated hydraulic fracturing in coal measure gas reservoir. The results of experimental test and theoretical analysis indicate that the formation permeability and breakdown pressure are the main factors affecting hydraulic fracturing process, and the formations with large difference in these two factors always induce an uneven distribution of fracturing fluid and poor effect of integrated hydraulic fracturing. High flow rate pumping injection rate is conducive to the even distribution of fracturing fluid in various formations. Meanwhile, the proper ball injection is used to limit fluid flowrate to ensure the fluid pressure in high permeability formation is higher than it in low permeability formation, fracturing fluid can flow to low permeability formation through perforation hole. In addition, interlayer crossflow occurs during the migration of fracturing fluid and causes fluid flow to low permeability formation, which is also conducive to the even fracturing. Therefore, high flow rate pumping injection, ball injection and interlayer crossflow control are effective measures for achieving the integrated hydraulic fracturing of coal measure gas reservoirs.

Condensate blockage effects in well test analysis of dual-porosity/dual-permeability, naturally fractured gas condensate reservoirs: a simulation approach

Fluid flow in gas condensate reservoirs usually exhibit complex flow behavior when the flowing bottomhole pressure drops below the dew-point. As a result, different flow regions with different characteristics are created within the reservoir. These flow regions can be identified by well test interpretation. The use of well test analysis for quantifying near well and reservoir behavior is well established for the case of simple single-layer homogenous systems. The behavior, however, is more complex in cases where different rock types or layering effects co-exist. In these cases, distinguishing between reservoir effects and fluid effects is challenging and needs a variety of analytical and numerical tools. The aim of this study is to investigate the liquid condensation effects on well test behavior of naturally fractured gas condensate through simulation approach in two different rock properties in a giant naturally fractured gas condensate field in south of Iran. A single well compositional model is developed to determine early-time, transition-time and late-time characteristics of the pressure transient data under condition of below dew-point pressure. Then compositional model has been used to verify the results obtained from conventional well test analysis in this field. The results of this study would improve modeling of the surrounding area in mentioned field. Interpretation of compositional model outputs have shown that condensate deposit near the wellbore yields a well test composite behavior in early and late time similar to what is found in single porosity homogenous system, but superimposed on double-permeability behavior. The behavior, however, is more complex in transition time which cause delay in hydrocarbon flow from the matrix blocks towards the fractures and lead to decrease in interlayer cross flow coefficient.

Well Testing Analysis for Variable Permeability Reservoirs

Abstract The effects of spatial permeability variations of a reservoir on the pressure derivative curve are studied. The presence of a permeability anomaly causes the pressure derivative to locally deviate from that of the corresponding homogeneous reservoir. For a simple variable permeability reservoir that has only one permeability anomaly, the start time, the value and the time of maximum local derivative deviation suggest the originating location, the permeability and the end location of the permeability anomaly, respectively. To analyze the transient pressure behaviour of a well located in a reservoir with multiple permeability anomalies, an approximate equation is presented. The study shows that the pressure derivative difference, with respect to that of the base homogeneous reservoir, is the summation of the pressure derivative differences of all simple variable permeability reservoirs with respect to the same base. This method has been proved and validated in reservoirs with radial and areal permeability distribution using both analytical and numerical methods. Applications show that this method provides a useful clue for well testing analysis of heterogeneous reservoirs and the maximum error caused by the proposed approximate equation is less than 3%. The practice guidelines for field test data interpretation are proposed. Introduction Traditional well testing analysis tends to determine an overall average permeability. Generally, it cannot reflect the spatial variation in the permeability of a reservoir. Typically, in practical well testing interpretation, the shape and the trend of the pressure derivative curve can be matched very well, but the local waves in the derivative curve cannot be matched at all. Generally, there are two sources producing local waves: the noise of tested data and the heterogeneity of the reservoir. The waves generated by the noise of tested data are random and discontinuous. This kind of wave may lead to interpretation errors. Consequently, many methods, such as wavelet analysis, Schroeter's deconvolution method and the optimal method, have been developed to de-noise the tested data. Different from the noise of tested data, the heterogeneity of the reservoir produces local continuous and smooth waves in the pressure derivative curve. Analyzing this kind of wave may provide more detailed reservoir information than traditional well testing. Many researchers have discussed some aspects of well testing analysis for heterogeneous reservoirs. Niko(1) presented analytical solutions for stratified and heterogeneous systems with interlayer crossflow. Yaxley(2) studied transient pressure behaviour when a partially communicating fault exists and observed that it can be diagnosed by drawing a semi-log derivative plot. Britto and Grader(3) studied the effects of size, shape and orientation of an impermeable region on transient pressure testing and found that the presence of an impermeable region caused the pressure response to deviate from the homogeneous line source response. They also pointed out that the four major parameters (the shortest distance between the well and the impermeable region, the size, the shape and the orientation of the region) affect the pressure response of the active source well located in such reservoirs. After investigating the transient pressure behaviours of wells located in composite reservoirs, Oliver(4, 5) derived a solution to the problem of a well located in an infinite reservoir with a small arbitrary spatial permeability variation, as demonstrated in the following equation:

Long-Term Performance of Multilaterals in Commingled Reservoirs

Abstract In this study, a comprehensive transient model was developed for multilateral wells producing from multiple formations separated by impervious streaks. The model is flexible and is capable of simulating the flow with any number of layers, unequal initial layer pressure, non-uniform petrophysical properties for each layer, and unequal layer size. Additionally, each lateral can have non-uniform formation damage and may be selectively completed. We investigated the long-term rate decline and cumulative recovery response of the multilateral wells connecting multiple isolated formations. Total flow rate, cumulative production, and fractional rate for each branch are all compared for several completion scenarios and layer properties. Crossflow between the layers through the wellbore is also evaluated. Introduction There have been many studies on modelling the fluid flow in horizontal wells in single-layer reservoirs or layered reservoirs with interlayer crossflow. In recent years, several studies focused on the productivity of multilaterals in homogeneous formations. To the author's knowledge, the literature provides only one study on the performance of a trilateral well in a three-layer commingled reservoir and one research study on the pressure transient characteristics of multilaterals in layered formations with crossflow. In many field applications, several non-communicating formations may be commingled only through a single undulating horizontal well or several sidetrack laterals emanating from a common pilot hole. The literature lacks a comprehensive investigation of the long-term performance of multilaterals commingling several isolated formations. Background Performance of vertical wells producing from commingled reservoirs has been the subject of many studies in the literature(1–4). However, most of the studies have focused on the transient pressure response of the commingled systems(1–3). Johnston and Lee(4) investigated the flow rate and cumulative production responses of low-permeability layers commingled through a vertical well. Inflow performance of a single horizontal lateral has been examined in detail by many investigators(5–12). Some studies only consider horizontal openholes(5–7). The effects of well completion schemes, such as partial penetration, undulation, perforating, and openhole gravel packing, on horizontal well performance have been discussed in several more recent studies(8–12). In recent years, multibranched wells have been proposed to improve hydrocarbon recovery and to accelerate production. Horizontal well performance with multiple laterals has been considered in several modelling studies(13–18). References (17) - (21) have reported the field applications of the multilaterals. Almost all the previous work on multilaterals addressed the issues related to production from a single formation or layered formations with interlayer crossflow. Among the previous studies, Vo and Madden(17) analyzed the production from a trilateral well commingling three isolated layers in the Dos Cuadras offshore field in California. Inflow Performance Model for Multilaterals in Commingled Reservoirs The physical model considered in this study is shown in Figure 1. The commingled multi-layer system considers an arbitrary number of isolated layers with different petrophysical properties and initial pressure. Impervious layers separate the reservoirs. It is assumed that there is only one lateral in each layer. All the laterals drilled into different layers may emanate from a common pilot hole, as depicted in Figur

Transient flowmeter test: semi-analytic crossflow model

The transient flowmeter test (TFMT) provides more information about the well–aquifer system than the traditional quasi-steady-state flowmeter test (QFMT). The TFMT duration may be much shorter than that of a QFMT, which is desirable at highly contaminated sites where the extracted water has to be treated as hazardous waste. Here we present the TFMT model that accounts for inter-layer crossflow, a thick skin surrounding the well, and wellbore storage. The model is derived under the simplifying assumptions of the pseudo-steady-state inter-layer crossflow and the uniform wellface flux within each layer. The semi-analytic solution is inverted numerically from the Laplace domain to the time domain. Layer and skin parameters are estimated from the TFMT data via the modified Levenberg–Marquardt algorithm. The estimation is robust when the initial parameter guesses are close to their true values. Otherwise, a computationally expensive search among the local minima of the objective function is necessary to find the parameter estimates. The modeling errors and the associated parameter estimation errors are evaluated in a number of synthetic TFMTs and compared to the corresponding results obtained with a general numerical model that relaxes the two simplifying assumptions. The TFMT provides reasonably accurate estimates of hydraulic conductivities for the aquifer layers and the damaged skins and order-of-magnitude estimates of layer specific storativities and hydraulic conductivities for the normal skin. The skin specific storativities should not be estimated from a TFMT. Multi-rate TFMTs with a step-variable pumping rate yield significantly more accurate parameters than constant-pumping-rate TFMTs. The calculated modeling errors may be useful in estimating the magnitude of parameter estimation errors from the TFMT. Our field tests in a coastal aquifer at the Lizzie Site in North Carolina (USA) demonstrate the feasibility of a TFMT for aquifer characterization. The downhole hydraulic conductivity profiles from our field and synthetic TFMTs are consistent with the corresponding profiles from QFMTs.

Well Test Analysis of Multi-Layered Naturally Fractured Reservoirs

Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains ten layers that are naturally fractured. The ten-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the two layers with the largest permeabilities. If this is used in reservoir studies together with the total net pay, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shut-in and the length of the wellbore storage period. Conclusions apply strictly only to the data set presented in this study. These conclusions, however, compare favorably with my observations in other naturally fractured reservoirs. Introduction Outcrop information, imaging logs, and production logs have shown that in some cases naturally fractured reservoirs are composed by many layers(1). The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1. A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft. perforated in a fractured reservoir only 5 to 10 ft. contribute production into the wellbore even if the 100 ft. are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures(1). FIGURE 1: Schematic of naturally fractured layered reservoir. Production log shows a couple of zones where fluids enter the wellbore. However, the whole section from top to bottom is net pay. (Available in full paper) One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al.(2) There was no communication between layers except at the wellbore. Later Russell and Prats(3) studied the practical aspects of interlayer crossflow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow.

Calculation of Wellbore Pressures and Rate Distribution in Multilayered Reservoirs

Summary An analytic procedure in Laplace space is developed to calculate the wellbore pressure and rate distribution, and their time rate of change, in anisotropic multilayer formations with axial symmetry and interlayer crossflow, in the presence of skins and wellbore storage, for any number of layers, any number of intervals open to the formation, for wells of nonzero radius, for finite external radii, and for no flow at the outer boundaries. Numerically, the procedure appears to be robust and trouble free. A number of applications to which the procedure can meaningfully be used are identified, and some elements of the procedure are illustrated through two brief examples.

Characterization of Tight Reservoirs

This paper gives methods to characterize tight gas reservoirs in sufficient detail to allow an engineer to make accurate long-range production forecasts. These forecasts are the bases for sound engineering and business decisions. Because of the complexity and variability of tight gas reservoirs, the authors can present only general procedures for developing reservoir descriptions. Accordingly, the authors illustrate a reservoir characterization method with three examples of successful tight gas reservoir studies. The procedures in these examples can be modified as needed for other specific formations or areas.

Rate Performance of a Layered Reservoir With Unsteady-State Interlayer Crossflow

Summary This paper presents an analytical solution for rate performance of a well intercepting a bounded two-layer reservoir. The solution is for modeling two-layer reservoirs with or without crossflow, with each layer having different layer skins and drainage radii. We present the effects of partial completion and of different layer skins and drainage radii on the rate behavior in layered reservoirs.

Pressure Behavior of Layered and Dual-Porosity Reservoirs in the Presence of Wellbore Effects

Summary This paper presents a new analytical solution for pressure-transient tests from layered reservoirs with or without crossflow. The analytical solution is for modeling layered-reservoir systems with unsteady-state or pseudosteady interlayer crossflow, commingled or stratified flow, and even dual-porosity systems with pseudosteady matrix-to-fracture transfer in the presence of skin, wellbore storage, and phase segregation.

Pressure Transients and Crossflow Caused by Diffusivities in Multilayer Reservoirs

Summary This paper considers single-phase unsteady flow in a system of homogeneous layers separated by thin, low-permeability shales, and having interlayer crossflow caused by different diffusivities for different layers. The model considers all layers open to a single well that flows at a constant total rate. Numerical simulations of the problem for the semipermeable-wall model are used to find the structure of the crossflows in typical cases. Analytic solutions for pressure and the n − 1 diffusivity crossflows are developed and compared with the numerical results. These solutions show how the diffusivity crossflows depend on layer properties and ordering. Their behavior and properties are discussed and their effects on pressure distributions are shown.

Determination of Parameters for Individual Layers in Multilayer Reservoirs by Transient Well Tests

Summary Approximate expressions for the pressure response and flow rates of individual layers are given when a well produces with a constant production rate from an infinite multilayer reservoir with and without interlayer crossflow. The kh product and skin factor of each layer can be determined by one drawdown test if the common wellbore pressure and the rate of each layer can be measured at the same time. The behavior of the crossflow, caused by skin factors, is discussed. A new method for determining the vertical permeabilities of the shales between layers is developed that uses the crosspoint of the two straight lines of drawdown or buildup curves. This method avoids measuring the wellbore pressures of the producing interval and the closed interval at the same time.

Matching Simulator Wellblock Pressures With Observed Buildup Pressures in Two-Layer Reservoirs

Summary An equation is given for the buildup time at which the wellbore pressure should match the kh average of the simulator wellblock pressures in history-matching procedures of two-layer reservoirs. The equation takes into account contrasts in flow capacities, porosity/compressibility/thickness products, and skin factors and makes use of fractional flow rates given by the simulator. The equation is derived for reservoirs without crossflow, but it can also be used for reservoirs with interlayer crossflow. Also included is a method to handle cases when only a single buildup pressure is recorded. To check the validity of the results, data from a three-dimensional (3D) reservoir simulator were compared with buildup data from an analytical solution for systems without crossflow and with data from a radial reservoir simulator for systems with crossflow.