Multi-fractured Horizontal Wells Research Articles

Estimation of fracture production and water breakthrough locations of multi-stage fractured horizontal wells combining pressure-transient analysis and electrical resistance tomography

The production of multi-stage fractured horizontal wells (MFHWs) decline fast, and water cut quickly increase after short producing period. How to evaluate well performance and estimate the water breakthrough segments become significant for improving oil recovery. The production logging test (PLT) enables to obtain the production profile along horizontal wellbore, however, it's difficult and expensive to carry out PLT for the MFHW. This work presents a new method to estimate production of hydraulic fractures and determine the water-breakthrough locations by combining pressure-transient analysis (PTA) and electrical-resistance tomography (ERT).This paper presents a PTA model of an MFHW which considers the nonuniform properties of fractures, including unequal fracture conductivity, nonuniform production distribution, asymmetric fractures, and arbitrary locations. The proposed model has been verified with the numerical PTA model in KAPPA Ecrin Saphir software. The type curves are developed and the impact of well and fracture properties on pressure and pressure derivative are also analyzed in detail. When the distance between fractures with high production (FHP) increases or number of FHP decreases, the early-radial flow can be obviously observed, and the duration of this regime depends on the interference among fractures. We define a parameter (N*) to describe the number of FHP, and the N* is determined by properties of hydraulic fractures. N* equals to N (total number of hydraulic fractures) if factures are symmetrically and uniformly distributed along wellbore and have equal production and conductivity. N* approximately equals to the number of producing fractures when all producing factures uniformly distribute along wellbore and have equal production, conductivity, and length. The developed PTA model is used to interpret production of different fractures by matching BHP data. The use of ERT enables to track water front, further estimate the water-breakthrough segments and reduce the non-uniqueness of PTA interpretation. The proposed approach is used to evaluate the well performance of MFHWs from Changqing Oil field, and interpretation results obtained in this work match with the results obtained by PLT.

Multi-fractured horizontal well for improved coalbed methane production in eastern Ordos basin, China: Field observations and numerical simulations

Eastern margin of Ordos basin has been an active commercial coalbed methane (CBM) production area in China, where coal seams are typically characterized with thin layers, low permeability and high gas content. Hydraulically fractured vertical wells (HFVWs) are the primary means for recovery of CBM in this area, which however are usually subject to low gas production and unpromising economics. Although the multi-fractured horizontal well (MFHW) has proven as an effective solution for producing hydrocarbon resources from both tight and shale reservoirs, its applicability in efficient development of CBM reservoirs remains yet unclear.This paper presents a pilot field application of MFHW to improve CBM recovery in eastern Ordos basin. A horizontal well stimulated with 6 stages of hydraulic fractures was observed to significantly outperform HFVWs in terms of depressurization efficiency, gas production and ultimate recovery factor. Peak gas rate of the MFHW is more than five times higher than an HFVW. History matches of the MFHW and representative HFVWs were conducted to obtain key reservoir properties that are subsequently used for production predictions. Numerical simulation predicts that cumulative gas production for the MFHW is 3–15 times as that for each of the HFVWs during a production duration of 15 years. A total of 500 stochastic geological scenarios for the study area were simulated to analyze the effect of geological parameters on the superiority of an MFHW over a group of four HFVWs (which are at equivalent well construction outlays) in terms of cumulative gas production. A correlation was then developed using the alternating conditional expectation (ACE) regression method, resulting in a linear relationship between an indicator of the superiority with permeability and desorption pressure in a log-log coordinate system. This correlation can be potentially used as a criterion for fast determination of the optimal completion option in the target CBM seams. The regression results also show that the superiority of an MFHW over HFVWs is especially highlighted in thin coal seams with low permeability and low gas content. Finally, the effect of the size and spacing of stimulated area (SA) on MFHW producibility was analyzed, showing that increasing the spacing between SAs is an economically viable option when the budget for fracturing operations is limited.

Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic-Fracture/Dynamic-Drainage-Area Leakoff Model Constrained by Laboratory Geomechanical Data

Summary The application of rate-transient-analysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic-fracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulic-fracture (fracture) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamic-drainage-area (DDA) concept was used to simulate water-based fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dual-porosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluid-leakoff simulation into the EFR and adding a proppant-transport model; and modeling the shut-in period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratory-derived propped (PHF) and unpropped (EFR) fracture-permeability/conductivity data as a function of pore pressure, as well as fracture-compressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.

A Discrete fracture–matrix model for pressure transient analysis in multistage fractured horizontal wells with discretely distributed natural fractures

Analysis of transient pressure test has become a reliable and powerful tool for petroleum engineers to study the impacts of complex fracture networks on multistage fractured horizontal wells (MFHWs) in unconventional reservoirs. Although lots of models have been established in the past decades, such as well-known dual-porosity model (DPM), dual-permeability model (DKM) and stripe fracture model (SFM), they have been proven unsuitable for modeling discretely distributed natural fractures (NFs).In this study, to overcome the disadvantages of existing models, a Discrete fracture–matrix method based on numerical well testing model (DFM-WTM) is proposed to study the pressure transient responses of MFHW with discretely distributed NFs. In DFM-WTM, local grid refinement method, well model and transmissibility corrections, natural fracture generation and time-step size are improved based on the framework of Matlab Reservoir Simulation Toolbox (MRST) (Lie, 2019), ensuring that pressure transient responses of MFHW with complex fracture networks can be obtained accurately and efficiently. Then, sensitivity analysis is conducted to study the impacts of different fracture properties. Finally, a case study is performed to further demonstrate the reliability and practicality of DFM-WTM.The results show that MFHW with discretely distributed NFs can be divided into 8 flow regimes, including (1) wellbore storage and skin effect, (2) fracture linear flow, (3) bilinear flow, (4) NF–HF fluid supply, (5) second bilinear flow, (6) formation linear flow, (7) pseudo boundary flow and (8) pseudo radial flow. Besides, a “dip” is found in the pressure derivative curve which is caused by the NF–HF fluid supply. Through the sensitivity analysis, it is found that this “dip” is an important signal to identify the impacts of NFs. It can also help us fathom the properties of HFs and NFs because this “dip” can be mainly affected by the number and conductivity of both HFs and NFs.

Post-flowback production data suggest oil drainage from a limited stimulated reservoir volume: An Eagle Ford shale-oil case

We analyze flowback and post-flowback production data from six multi-fractured horizontal wells completed in Eagle Ford shale formation. Petrophysical analysis of samples from an offset well shows that the target shale is in oil window with type II kerogen. We analyze two groups of wells with different well-completion and operational parameters. Wells fractured with slickwater, with higher total injected volume (TIV) and larger choke size show higher initial oil rate, but faster pressure depletion compared with the wells fractured with cross-linked gel, with lower TIV and smaller choke size. Both groups show supercharged fractures when flowback starts and reservoir pressure remains above bubble point during post-flowback period. Interestingly, rate-normalized pressure plots of oil and water from both groups during post-flowback period show pronounced unit slope indicating boundary dominated flow (BDF), while this trend is not observed during flowback period. Analysis of rate-normalized pressure and rate-decline data suggests that both oil and water are produced from a closed tank under BDF conditions. We propose a multiphase flowing material balance (FMB) model to describe water and oil production from an effective stimulated reservoir volume (ESRV) during post-flowback period. The proposed FMB model assumes negligible oil and water influx into ESRV. The driving forces considered are closure of fractures and expansion of oil and water in ESRV. Applying the proposed model on post-flowback data confirms that after fracture depletion, oil is produced from highly stimulated matrix around hydraulic fractures while water is mainly produced from fractures.

Productivity simulation of hydraulically fractured wells based on hybrid local grid refinement and embedded discrete fracture model

Abstract Using current Embedded Discrete Fracture Models (EDFM) to predict the productivity of fractured wells has some drawbacks, such as not supporting corner grid, low precision in the near wellbore zone, and disregarding the heterogeneity of conductivity brought by non-uniform sand concentration. An EDFM is developed based on the corner grid, which enables high efficient calculation of the transmissibility between the embedded fractures and matrix grids, and calculation of the permeability of each polygon in the embedded fractures by the lattice data of the artificial fracture aperture. On this basis, a coupling method of local grid refinement (LGR) and embedded discrete fracture model is designed, which is verified by comparing the calculation results with the Discrete Fracture Network (DFN) method and fitting the actual production data of the first hydraulically fractured well in Iraq. By using this method and orthogonal experimental design, the optimization of the parameters of the first multi-stage fractured horizontal well in the same block is completed. The results show the proposed method has theoretical and practical significance for improving the adaptability of EDFM and the accuracy of productivity prediction of fractured wells, and enables the coupling of fracture modeling and numerical productivity simulation at reservoir scale.

Effects of Entrained Hydrocarbon and Organic-Matter Components on Reservoir Quality of Organic-Rich Shales: Implications for “Sweet Spot” Identification and Enhanced-Oil-Recovery Applications in the Duvernay Formation (Canada)

Summary The hydrocarbon (HC)-storage capacity of organic-rich shales depends on porosity and surface area, whereas pore-throat-size distribution and pore-throat-network connectivity control permeability. The pores within the organic matter (OM) of organic-rich shales develop during thermal maturation as different HC phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the HCs generated during the diagenesis process. Commercial HC production from liquid-rich shale reservoirs can be achieved using completion technologies such as multistage-fractured horizontal wells. However, the ability of industry to identify “sweet spots” along multistage-fractured horizontal wells for both primary and enhanced oil recovery (EOR) is still hampered by insufficient understanding of the effects of type/content of entrained HC/OM components on reservoir quality. The primary objectives of the current study are therefore to establish an integrated experimental workflow to investigate the effect of entrained HC/OM on storage and transport properties of the organic-rich shales, and to provide examples of that experimental workflow through analyzing a selected sample suite from a prolific shale-oil reservoir (the Duvernay Formation) in western Canada. To accomplish this goal, a comprehensive suite of petrophysical analyses is performed on a diverse sample suite from the Duvernay Formation that differs in OM content (2.8 to 5 wt%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis [extended-slow-heating (ESH) Rock-Eval analysis]. Using the ESH cycle, different HC/OM components can be distinguished more easily and reliably during the pyrolysis process: free light oil (S1ESH; up to 150°C), fluid-like HC residue (FHR) (S2a; 150 to 380°C), and solid bitumen/residual carbon (S2b; 380 to 650°C). The characterization techniques used at each stage are helium pycnometry (grain density, helium porosity); low-pressure gas [nitrogen (N2), carbon dioxide (CO2)] adsorption (LPA) [pore volume (PV), surface area, pore-size distribution (PSD) within micropores, mesopores, and smaller macropores]; crushed-rock gas [helium, CO2, N2] permeability; and rate-of-adsorption (ROA) analysis (CO2, N2). Scanning-electron-microscopy (SEM) analysis is further conducted to verify/support the petrophysical observations. Powder X-ray-diffraction (XRD) analyses were performed on all samples in the “as-received” state and after Stage S2b (thermal pyrolysis up to 650°C) to quantify variations in mineralogical compositions and their possible controls on the evolution of petrophysical properties (i.e., porosity/permeability). Organic petrography was conducted on selected samples to characterize the nature of OM. Compared with the “as-received” state, porosity, permeability, modal-pore-size distribution, and surface-area increase with sequential pyrolysis stages, associated with the expulsion and devolatilization of free light oil and FHR (S2a; up to 380°C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650°C) is variable and unpredictable. The observed reduction in porosity/permeability values after Stage S2b is likely attributed to the occlusion of PV with solid bitumen/residual carbon degradation (i.e., coking); sample swelling caused by water loss from the lattice structure of clay minerals (i.e., illite); and sample compaction as a result of OM removal from the rock matrix. Among various stages of the ESH Rock-Eval pyrolysis, the petrophysical properties that are measured after Stages S1ESH and S2a, as they are related to the expulsion of the lighter and heavier free-HC compounds from the rock matrix, are expected to be the most important for primary and EOR applications. Quantification of the evolution of reservoir quality with HC generation/expulsion has important implications for identifying petrophysical “sweet spots” within unconventional reservoirs, optimizing stimulation design, and targeting specific zones within the reservoir of interest with the OM content/type amenable to maximizing gas storage/transport during cyclic solvent injection for EOR applications. The integrated experimental workflow proposed herein could be of significant interest to the operators of organic-rich shale/mudstone plays (e.g., the Duvernay) as a screening tool for developing optimized stimulation treatments for improving primary and enhanced HC recovery.

Quantifying Total Apparent Hydraulic Fracture Conductivity and Its Significant Degradation from Systematic Bottomhole Pressure Measurements in Permian Wells

SummaryHydraulic fractures play a central role in the performance of multistage fractured horizontal wells (MFHWs) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e., choking skins) strongly affect well productivity. However, convincing and high-quality evaluations of hydraulic fractures for these reservoirs are rare in literature because quantifying fracture properties requires decoupling them from fracture geometry and formation properties, a difficult task in most field conditions. A data gathering and hypothesis testing program was implemented using six multifractured horizontal wells in a pad in the Delaware Basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut-ins, and bottomhole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses to characterize the hydraulic fractures; namely, pressure transients for individual wells and significant well-to-well interference signals. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but there is a large difference in the uncertainty of the estimated results from these two methods.The first method used a radial/linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows decoupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and borehole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plots with minimum assumptions. Specifically, the estimated TAFC ranges from 1,140 to 1,630 md-ft at early time of well life to 525 to 855 md-ft after 100 to 139 days in production, or about a 45 to 61% reduction among these wells.The second method uses time-lag of pulse interference responses between an active and observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility, and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial/linear flow regime.The results of this work provide a better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between the hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.

Transient Flow of a Horizontal Well with Multiple Fracture Wings in Coalbed Methane Reservoirs

Horizontal wells with multi-stage fractures have been widely used to improve coalbed methane (CBM) production from coalbed methane reservoirs. The main focus of this work is to establish a new semi-analytical method in the Laplace domain and investigate the transient pressure behavior in coalbed methane reservoirs. With the new semi-analytical method, flow regimes of a multi-fractured horizontal well in coalbed methane reservoirs were identified. In addition, the sensitivities of fracture conductivity, diffusion model, storability ratio, inter-porosity flow coefficient, adsorption index, fracture spacing, fracture asymmetry, non-planar angle, and wellbore storage were studied. Results indicate that six characteristic flow regimes can be identified for multi-fractured horizontal wells in coalbed methane reservoirs, which are bilinear flow, first linear flow, desorption-diffusion flow, first pseudo-radial flow, second linear flow, and second pseudo-radial flow. Furthermore, the sensitivity analysis shows that the early flow is mainly determined by the fracture conductivity, the asymmetry factor, the non-planar angle, and the wellbore storage; while the desorption-diffusion flow regime is mainly influenced by the diffusion model, the storability ratio, the inter-porosity flow coefficient, the adsorption index, and the fracture spacing. Our work can provide a deep insight into the fluid flow mechanism of multi-fractured horizontal wells in coalbed methane reservoirs.

A new production prediction model for multistage fractured horizontal well in tight oil reservoirs

To better evaluate the production performance of tight oil reservoirs, it is urgent to solve the multistage fractured horizontal well production enigma. It is paramount to develop new models to analyze the well performance for tight oil reservoirs. In this paper, a new production prediction model of multistage fractured horizontal well in tight oil reservoir was established. In this model, unsteady transfer flow between fracture and matrix was considered. This model was solved by using Laplace transform method, line source function and Stehfest method comprehensively. The production prediction type curves including pressure transient analysis curves and rate transient analysis curves were then obtained. According to these type curves, eight flow regimes were obtained as early wellbore storage period, skin factor period, bi-linear flow regime, linear flow regime, first radial flow regime, transition flow regime, transfer flow regime and later radial flow regime. In the end, a field case history matching result was given and four key parameters’ effect on tight formation well production was analyzed. This research is of both theoretical significance and practical value for tight oil development. Cited as : Zhao, K., Du, P. A new production prediction model for multistage fractured horizontal well in tight oil reservoirs. Advances in Geo-Energy Research, 2020, 4(2): 152-161, doi: 10.26804/ager.2020.02.04

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

Assessment of Production Interference Level Due to Fracture Hits Using Diagnostic Charts

Summary The objective of this study is to develop a new method that leads to diagnostic charts that quantify the pressure response between two interfering wells. Analytical linear flow models for single hydraulic fracture are used to develop a fracture hit model, which is next verified with a numerical model for validity. An analytical two-fracture model is then developed to simulate flowing bottomhole pressure (BHP) of a shut-in well, which interferes with the other well through a fracture hit, during well-testing for a short-term period. From the insight of two-fracture analytical model, a dimensionless pressure scalar, which is proportional to square root of time, is proposed to summarize the interference level between two wells. Utilizing such proportionality between the defined dimensionless pressure scalar and square root of time, a diagnostic chart for quick assessment of the production interference level between wells is developed. Such diagnostic chart is also applied to interference caused by multifracture hits that a multistage fractured horizontal well with history match performed from the Eagle Ford formation is considered as a parent well for production interference quantification. A new identical horizontal well, which is just fractured but is not in production, is assumed parallel to the pre-existing well. The result shows that when the percentage of fracture connection increases, the slope of dimensionless pressure scalar vs. square root of time increases proportionally to the percentage of fracture connection. Because the slope of dimensionless pressure scalar vs. square root of time is between 0 and 1, it can be used to quantify the well production interference level under different situations.

Type-curve analysis of modified two-rate flow test: A simple yet effective technique to minimize the non-uniqueness of interpretation results

Two-rate flow test is widely used in petroleum industry to determine reservoir parameters because its advantage of avoiding the need of shutting in the well. Field practice of hundreds of wells in Changqing Oilfield, China, show that lacking the pressure data before production-rate change period during the two-rate flow test – which is a customary rule in the pressure measurement – is likely to bring about unreasonable interpretation results. In this paper, we extend the three-rate flow test (Selim, 1967) by applying Gringarten-Bourdet type curve analysis method, rather than specialized plot, to analyze the testing pressure behavior. This method, we call it modified two-rate flow (MTRF) technique, is tested by measuring a short period of pressure data for an extra production rate (usually it is designed back to initial stabilized condition to reduce the production losses) based on conventional two-rate flow test. As a result, the total measurement time for the MTRF test is nearly equal to, or slightly longer than, conventional two-rate flow test, and much shorter than three-rate flow test. The mathematical justification of Gringarten-Bourdet type curve that applied in MTRF test is re-derived, and the well test designs for horizontal and multi-fractured horizontal wells are conducted to validate the applicability of the MTRF method. Results show that the results of conventional two-rate flow tests are largely dependent on the initial parameters we set, while the results obtained by MTRF method are very close to the correct values even with different and far away initial values. This new technique not only reserves the same advantages as two-rate technique, but also minimizes the non-uniqueness of the results by add an extra pressure history, thus providing a double-check of the results, like permeability, reservoir pressure, and so on.

An Analytical Solution for Transient Productivity Prediction of Multi-Fractured Horizontal Wells in Tight Gas Reservoirs Considering Nonlinear Porous Flow Mechanisms

Multi-fractured horizontal wells (MFHW) is one of the most effective technologies to develop tight gas reservoirs. The gas seepage from tight formations in MFHW can be divided into three stages: early stage with high productivity, transitional stage with declined productivity, and final stage with stable productivity. Considering the characteristics and mechanisms of porous flows in different regions and at different stages, we derive three coupled equations, namely the equations of porous flow from matrix to fracture, from fracture to near wellbore region, and from new wellbore region to wellbore then an unstable productivity prediction model for a MFHW in a tight gas reservoir is well established. Then, the reliability of this new model, which considers the multi-fracture interference, is verified using a commercial simulator (CMG). Finally, using this transient productivity prediction model, the sensitivity of horizontal well’s productivity to several relevant factors is analyzed. The results illustrate that threshold pressure gradient has the most significant influence on well productivity, followed by stress sensitivity, turbulence flow, and slippage flow. To summarize, the proposed model has demonstrated a potential practical usage to predict the productivity of multi-stage fractured horizontal wells and to analyze the effects of certain factors on gas production in tight gas reservoirs.

Lab-Supported Hypothesis and Mathematical Modeling of Crack Development in the Fluid-Soaking Process of Multi-Fractured Horizontal Wells in Shale Gas Reservoirs

The objective of this study is to develop a technique to identify the optimum water-soaking time for maximizing productivity of shale gas and oil wells. Based on the lab observation of cracks formed in shale core samples under simulated water-soaking conditions, shale cracking was found to dominate the water-soaking process in multi-fractured gas/oil wells. An analytical model was derived from the principle of capillary-viscous force balance to describe the dynamic process of crack propagation in shale gas formations during water-soaking. Result of model analysis shows that the formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures and reduce fracture width, and consequently lower well inflow performance. The tradeoff between the crack development and fracture closure allows for an optimum water-soaking time, which will maximize well productivity. Reducing viscosity of fracturing fluid will speed up the optimum water-soaking time, while lowering the water-shale interfacial tension will delay the optimum water-soaking time. It is recommended that real-time shut-in pressure data are measured and shale core samples are tested to predict the density of cracks under fluid-soaking conditions before using the crack propagation model. This work provides a shut-in pressure data-driven method for water-soaking time optimization in shale gas wells for maximizing well productivity and gas recovery factor.

Pressure performance of multi-stage fractured horizontal well with stimulated reservoir volume and irregular fractures distribution in shale gas reservoirs

With the development of hydraulic fracturing technology of horizontal well, most unconventional gas reservoirs are developed by horizontal well multi-stage fracturing technology to improve gas well production. In this paper, we present a semi-analytical model of multi-stage fractured horizontal well (MFHWs) with consideration of adsorbed gas desorption and the irregular hydraulic fractures distribution in shale gas with the stimulated reservoir volume (SRV). On the bases of the point source function, Langmuir isotherm adsorption and Fick's law, wellbore pseudo-pressure solution of finite-conductivity MFHWs model is obtained by employing Laplace transform, finite cosine Fourier transform. and the discrete fracture approach in shale gas. The pressure transient responses log-log curves of MFHWs are drawn by Gauss elimination method and Stehfest numerical algorithm. In the light of the characteristics of the pressure derivative curve, the characteristics of each flow stage are identified and analyzed in detail. With the comparison of the commercial well test software numerical solution and the previous literature, the comparison results reach a good agreement under condition of same parameter. The effects of vital parameters, such as hydraulic fractures number and size of the SRV region, hydraulic fractures distribution styles and crossflow coefficient, on pressure transient curve are analyzed in detail. The presented model in this paper not only provides some insights for pressure dynamic analysis of shale gas reservoir development, but can help to engineers understand the pressure dynamics in shale gas reservoirs with SRV and irregular fracture distribution.

A New Straight-Line Analysis Method for Estimating Fracture/Reservoir Properties Using Dynamic Fluid-in-Place Calculations

SummaryStraight-line analysis (SLA) methods, which are a subgroup of model-based techniques used for rate-transient analysis (RTA), have proved to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulic-fracture information, whereas boundary-dominated-flow (BDF) data can be interpreted for fluid-in-place estimates. Because transient-flow periods might be extensive, it is also advantageous to evaluate the volume of hydrocarbons in place contacted over time to assist with reserves assessment. The new SLA method introduced herein enables reservoir/fracture properties and contacted fluid in place (CFIP) to be estimated from the same plot, which is an advantage over traditional SLA techniques.The new SLA method uses the Agarwal (2010) approach for CFIP estimation, extended to variable-rate/pressure data for low-permeability (unconventional) reservoirs. A log-log plot of CFIP vs. material-balance time (for liquids) or material-balance pseudotime (for gas) is created, which typically exhibits power-law behavior during transient flow, and reaches a constant value [original fluid in place (OFIP)] during BDF. Although CFIP calculations do not assume a flow geometry, the SLA method requires this to extract reservoir/fracture information. Herein, transient linear flow (TLF) is assumed and used for the SLA-method derivation, which allows the linear-flow parameter (LFP) to be extracted from the y-intercept (at material-balance time or material-balance pseudotime = 1 day) of a straight-line fit through transient data. OFIP can also be obtained from the stabilization level of the CFIP plot.Validation of the new SLA method for an undersaturated oil case is performed through application to synthetic data generated with an analytical model. The new SLA results in estimates of LFP and OFIP that are in excellent agreement with model input (within 2%). Further, the results are consistent with the traditional SLA methods used to estimate the LFP (e.g., the square-root-of-time plot) and the OFIP (e.g., the flowing material-balance plot).Practical application of the new SLA method is demonstrated using field cases and experimental data. Field cases studied include online oil production from a multifractured horizontal well (MFHW) completed in a tight oil reservoir, and flowback water production from a second MFHW, also completed in a tight oil reservoir. Experimental (gas) data generated using a recently introduced RTA core-analysis technique were also analyzed using the new SLA method. In all cases, the new SLA-method results are in excellent agreement with traditional SLA methods.The new SLA method introduced herein is an easy to apply, fully analytical RTA technique that can be used for both reservoir/fracture characterization and hydrocarbon-in-place assessment. This method should provide important, complementary information to traditionally used methods, such as square-root-of-time and flowing material-balance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs.The method is currently limited to cases exhibiting single-phase flow, the flow-regime sequence of TLF to BDF, and reservoir homogeneity. In future work, these limitations will be resolved.

Evaluation of the impact of multi-phase flow on reservoir signatures in the Wolfcamp shale

The dominant transient flow regime for multi-fractured horizontal wells (MFHWs) producing from low-permeability and shale (unconventional) reservoirs has historically been interpreted to be transient linear flow (TLF) with analysis performed in the framework of classical diffusion (CD). Recently, observed deviations away from this classical behavior for Permian Basin Wolfcamp shale (oil) wells have been attributed to reservoir heterogeneity and anomalous diffusion (AD). However, some wells in the basin also produce below bubble point pressure and exhibit characteristics of multi-phase flow. The objective of the current study is therefore to investigate if multi-phase flow may also be contributing to observed deviations from classic TLF behavior.The conventional log-log diagnostics used to identify flow regimes do not account for reservoir complexities such as multi-phase flow and reservoir heterogeneity. Failure to correct for these effects when they are occurring may result in misdiagnosis of flow regimes. A new workflow is therefore introduced herein to improve flow regime identification when reservoir complexities are exhibited, with a specific focus on multi-phase flow. The workflow involves the correction of log-log diagnostics for multi-phase flow through the use of modified pseudo-variables (pseudo-pressure and pseudo-time) once characteristics of multi-phase flow are identified (e.g. rapid increase of gas-oil ratio after bubble point pressure is reached). Although reservoir heterogeneity and AD are accepted causes of deviations from TLF, the impact of multi-phase flow has not been investigated in detail. Therefore, corrections to pseudo-variables for multi-phase flow, a known reservoir complexity exhibited by Wolfcamp shale wells, are presented. Pressure-dependent permeability is also accounted for in pseudo-variable calculations, although its impact is demonstrated to be relatively minor in this study.Application of the new workflow to a simulated case and a Wolfcamp shale field case demonstrates the following: 1) multi-phase flow, and in particular the appearance of a mobile gas phase after two-phase oil and water production, results in deviations from classical TLF behavior when data is analyzed using conventional (uncorrected) diagnostics; 2) application of the modified diagnostics to a simulated case that includes multi-phase flow results in the “true” flow regime signature of TLF being observed; 3) application of the modified diagnostics to a field case exhibiting evidence of multi-phase flow reduces the deviation from TLF.This study suggests that multi-phase flow may be impairing our ability to identify flow regimes using conventional flow regime identification methods.

A numerical method for simulating planar 3D multi-fracture propagation in multi-stage fracturing of horizontal wells

To resolve the issue of design for multi-stage and multi-cluster fracturing in multi-zone reservoirs, a new efficient algorithm for the planar 3D multi-fracture propagation model was proposed. The model considers fluid flow in the wellbore-perforation-fracture system and fluid leak-off into the rock matrix, and uses a 3D boundary integral equation to describe the solid deformation. The solid-fluid coupling equation is solved by an explicit integration algorithm, and the fracture front is determined by the uniform tip asymptotic solutions and shortest path algorithm. The accuracy of the algorithm is verified by the analytical solution of radial fracture, results of the implicit level set algorithm, and results of organic glass fracturing experiment. Compared with the implicit level set algorithm (ILSA), the new algorithm is much higher in computation speed. The numerical case study is conducted based on a horizontal well in shale gas formation of Zhejiang oilfield. The impact of stress heterogeneity among multiple clusters and perforation number distribution on multi-fracture growth and fluid distribution among multiple fractures are analyzed by numerical simulation. The results show that reducing perforation number in each cluster can counteract the effect of stress contrast among perforation clusters. Adjusting perforation number in each cluster can promote uniform flux among clusters, and the perforation number difference should better be 1-2 among clusters. Increasing perforation number in the cluster with high in situ stress is conducive to uniform fluid partitioning. However, uniform fluid partitioning is not equivalent to uniform fracture geometry. The fracture geometry is controlled by the stress interference and horizontal principal stress profile jointly.

Transient pressure behavior for unconventional gas wells with finite-conductivity fractures

Horizontal wells and hydraulic fracturing technologies are the only way that makes commercial production from the low and ultra-low permeability unconventional plays possible. The development of analytical and semi-analytical tools to analyze transient behavior of multi-fractured horizontal gas wells have been largely biased towards solving the simplified problem of one-dimensional (1D) Cartesian gas flow in matrix domain, which are only applicable to the production from infinite-conductivity fractures. This study presents a novel semi-analytical method for transient behavior analysis of horizontal gas wells producing from finite-conductivity fractures. Unlike the available transient analysis tools for finite-conductivity fractures which are developed based on empirical and approximate solution, the proposed solution is rigorously derived by solving the governing gas diffusivity equations written for gas flow in two contiguous regions of matrix and fracture simultaneously. Nonlinear, pressure-dependent gas properties remaining in pseudopressure-based diffusivity equations—namely viscosity and compressibility—are rigorously and straightforwardly captured in both fracture and matrix systems. The validity of proposed solution is verified against commercial numerical simulator (COMSOL Multiphysics®) for a series of synthetic cases considering constant and variable -rate production constraints. The case studies presented in this paper also showcase the applicability of proposed solution to the analysis of transient behavior of multi-fractured horizontal gas wells in shale plays under the following two state-of-the-art interpretations: 1) production from finite-conductivity hydraulic fractures in a single-porosity matrix; and 2) production from infinite-conductivity hydraulic fractures in a naturally-fractured matrix.