Yu, Haiyang

Applications of cluster wells and hydraulic fracturing enable commercial productivity from unconventional reservoirs. However, well productivity decrease rapidly for this type of reservoirs, and in many cases, it is difficult to maintain a productivity that is economical. Enhanced oil recovery (EOR) is therefore needed to improve well performance. Traditional fluid injection from other wells are not feasible due to the ultra-low permeability, and fluid Huff-n-Puff also fails to meet the expected recovery. This work investigates the feasibility of the inter-fracture injection and production (IFIP) approach to increase oil production of multiple multi-fractured horizontal wells (MFHW).

Three MFHWs are considered in a cluster well. Each MFHW includes injection fractures (IFs) and recovery fractures (RFs). The fractures with even and odd indexes are assigned to be IFs or RFs, respectively. The injection/production schedule falls into two categories: synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). To analyze the well performance of multiple MFHWs using the IFIP method, this work performs numerical simulation based on the compartmental embedded discrete fracture model (cEDFM) and compares the production performance of three MFHWs using four different producing methods (i.e., primary depletion, CO₂ Huff-n-Puff, s-IFIP, and a-IFIP). Although the number of producing fractures is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than primary depletion and CO₂ Huff-n-Puff. Sensitivity analysis is performed to investigate the impact of parameters on the IFIP. The fracture spacing between IFs and RFs, CO₂ injection rates, and connectivity of fracture networks affect the oil production significantly, followed by length of RFs, well spacing among MFHWs and length of IFs. The suggested well completion scheme is presented for the a-IFIP and s-IFIP methods. This work demonstrates the ability of the IFIP method in enhancing oil production of multiple MFHWs in unconventional reservoirs.

Poor energy supplement and low hydrocarbon recovery are the two main shortcomings for water or gas injection in tight oil reservoir development. Horizontal well flooding can improve oil recovery and sweep efficiency of water flooding. However, the economic benefits need to be considered for long horizonal well injection. Based on a case of Changqing Oil filed, this paper presents a novel development approach, Allied In-Situ Injection and Production (AIIP), for fractured horizontal wells to increase hydrocarbon recovery, and explores its feasibility with simulation work, compared with traditional water flooding method. The impact for the existence of natural fractures in tight oil reservoir is also studied in this work. Although requiring costly special equipment, a series of simulations prove that AIIP is a more reliable and efficient approach to increase the performance of fractured horizontal wells compared to conventional methods, oil recovery and oil rate were improved significantly after AIIP was conducted. Water injectivity increased sharply than traditional water flooding with a lower injection pressure. The existence of natural fracture in tight oil formation improved the water flow inside the formation, leading better sweep efficiency and higher oil recovery factor. However, water cut in producers increased faster in natural facture enriched model than that of basic model. Thereforem it is essential to evaluate the performance of AIIP process before application.

Propping agents inside hydraulic fractures perform significant role in constructing high-speed flow channel to deliver fluids into wellbore. However, proppant transport in fracture is always influenced by many factors, resulting unpropped fracture. Under such situation, this paper proposes a novel pressure-transient analysis method to better interpreted created fracture properties. The application of signal amplification technology is conducted on pressure transient analysis to deal with non-uniqueness problems. Aiming at transient linear flow, trilinear flow model in fractured wells is further modified and upgraded to characterize unpropped segments. Based on the solutions, this study applied signal amplification technology to extract weak-signals to assist early-time pressure transient analysis. The new type curves regarding with pressure response in partially unpropped fracture is then generated to capture the characteristics of this phenomenon. Subsequently, sensitivity analyses make clear the effects of key parameters on pressure response, which shows the superiorities of the new type curves in pressure transient analysis. The approaches proposed by this paper undoubtly will help solve inverse problems of wells exhibiting long-period linear flow in tight reservoirs.

High water-cut has been observed for many multi-fractured horizontal wells (MFHWs) in China soon after waterflooding begins. Available well-testing models of single well ignored the effect of adjacent wells on the MFHW, and they are unable to evaluate whether MFHW (producer) and surrounding vertical wells (injectors) are in good pressure communication. To fill this gap, this work presents a multi-well interference testing (MWIT) model to consider the interference of injectors and further match the interference pressure data.

The MWIT model is established to investigate the effect of multiple injection wells on transient-pressure behavior of the MFHW. Due to the interferences from injectors, the pressure and pressure-derivative curves of MWIT move down beginning with the biradial flow regime for single MFHW model, and pseudo-radial flow (horizontal line with the value of 0.5 on pressure-derivative curve) disappears. Sensitivity analysis was conducted to discuss the effects of crucial parameters on the pressure response, including total injection rates, unequal injection rates of injectors, well spacing, injector distribution, number and production of hydraulic fractures. When total injection rates are lower than the production rate, the pressure derivative will eventually stabilize at 0.5*(1-Σ(q_IncjD)) during the interference-flow regime on the log-log type curves. Since only the positive number can be shown in the log-log graph, semi-log curves are also developed to fully characterize the flow regimes of MWIT. A novel finding is that pressure derivative also ultimately behave as a horizontal line with the value of 0.5*(1-Σ(q_IncjD)) when total injection rates are equal or higher than production rates on the semi-log curves. The total injection rates and well spacing between the MFHW and injectors have a significant effect on middle and late pressure behaviors, whereas the number and production of fractures mainly affects the pressure responses during early to middle period. Type curves indicate that the effect of surrounding injectors are significant and cannot be ignored, and the novel characteristics provide potential application of the MWIT model to estimate formation parameters. Case studies highlight the application of the proposed method in effectively matching the interference pressure data. Interference-testing analysis of the MWIT provides a better reservoir evaluation compared to single-well testing model.

High water-cut has been observed for many multi-fractured horizontal wells (MFHWs) in China soon after waterflooding begins. Available well-testing models of single well ignored the effect of adjacent wells on the MFHW, and they are unable to evaluate whether MFHW (producer) and surrounding vertical wells (injectors) are in good pressure communication. To fill this gap, this work presents a multi-well interference testing (MWIT) model to consider the interference of injectors and further match the interference pressure data.

The MWIT model is established to investigate the effect of multiple injection wells on transient-pressure behavior of the MFHW. Due to the interferences from injectors, the pressure and pressure-derivative curves of MWIT move down beginning with the biradial flow regime for single MFHW model, and pseudo-radial flow (horizontal line with the value of 0.5 on pressure-derivative curve) disappears. Sensitivity analysis was conducted to discuss the effects of crucial parameters on the pressure response, including total injection rates, unequal injection rates of injectors, well spacing, injector distribution, number and production of hydraulic fractures. When total injection rates are lower than the production rate, the pressure derivative will eventually stabilize at 0.5*(1-Σ(q_IncjD)) during the interference-flow regime on the log-log type curves. Since only the positive number can be shown in the log-log graph, semi-log curves are also developed to fully characterize the flow regimes of MWIT. A novel finding is that pressure derivative also ultimately behave as a horizontal line with the value of 0.5*(1-Σ(q_IncjD)) when total injection rates are equal or higher than production rates on the semi-log curves. The total injection rates and well spacing between the MFHW and injectors have a significant effect on middle and late pressure behaviors, whereas the number and production of fractures mainly affects the pressure responses during early to middle period. Type curves indicate that the effect of surrounding injectors are significant and cannot be ignored, and the novel characteristics provide potential application of the MWIT model to estimate formation parameters. Case studies highlight the application of the proposed method in effectively matching the interference pressure data. Interference-testing analysis of the MWIT provides a better reservoir evaluation compared to single-well testing model.

Yang Wang, China University of Petroleum, Beijing, and Pennsylvania State University; Shiqing Cheng, China University of Petroleum, Beijing; Kaidi Zhang, Lusheng Petroleum Development Company Limited, Sinopec Shengli Oilfield Company; Youwei He, China University of Petroleum, Beijing, and Texas A&M University; and Naichao Feng, Jiazheng Qin, Le Luo, and Haiyang Yu, China University of Petroleum, Beijing Summary It is well-known that water injection may induce formation fracturing in tight reservoirs. Especially when the field-geology condition is complex and the waterflood-induced fractures (WIFs) are not well-identified in time, the induced fractures can be of the same order as the well spacing, which has a significant, and generally undesired, impact on both areal sweep and vertical conformance. Therefore, the onset of WIFs must be identified in a timely manner, and the waterflooding performance must be evaluated comprehensively to formulate an appropriate strategy over time. A new work flow, containing analytical/semianalytical, statistical, and numerical techniques that are based on flow-rate/BHP and formation-testing data, is applied to identify the WIFs, diagnose waterflooding direction and front distribution, analyze interwell connectivity, and interpret abnormal bottomhole-pressure (BHP) behaviors in the Changqing Oil field. The work flow includes three modules: First, real-time monitoring and analysis, including modified Hall plot, evolving skin analysis, and injection/fracturing index methods, are used to identify the start of WIFs. Then, the formation-testing module, consisting of step-rate test (SRT), radioactivetracer logging, and passive seismic method, is applied to investigate the formation-fracturing pressure, and uneven waterflooding performance in the areal and vertical directions. On the basis of the two former modules, we adapt the third module, which includes injector/producer relationships (IPRs) and the constrained multiple-linear-regression (MLR) method, to quantitatively investigate the waterflooding direction by injection/production rates. A new model--injection well with waterflood-induced fracture (IWWIF)--is proposed to characterize the abnormal BHP behaviors considering the properties variation (shrinking fracture length and decreasing fracture conductivity) of WIFs during the falloff period. Compared with an individual method, the ITD (which is the abbreviation of WIF identification, formation testing, and dynamic production analysis) work flow is developed to obtain a comprehensive and deep understanding of waterflooding performance. The main emphasis of this study is to integrate different approaches to address the key uncertainties rather than analyze each data source individually. On the basis of the results obtained by this work flow, the operators can make a more-proactive and -reasonable decision on waterflooding management.

Abstract

In this paper, a novel model is proposed to characterize superheated steam-air (SSA) pressure and temperature distribution in horizontal wells with toe-point injection technique. Firstly, the mathematical model of SSA flow in both tubing and annulus is established based on the mass, momentum and energy conservation equations, and it is solved by employing finite difference method. The mass and heat transfer are coupled with injection of SSA into formation and heat exchange between tubing and annulus by iterative technique. Then, the proposed model is validated by field data. Finally, the effect of mass fraction of air and injection temperature on SSA temperature, pressure, mass flow rate in annulus and heat transfer rate from annulus fluid to formation are conducted.

Results indicate that: (1). The SSA temperature in tubing decreases while flowing from heel point to toe point and the temperature gradient decreases with distance to heel point. (2). The SSA temperature in annulus first decreases and then turns to increase while flowing from toe point to heel point. (3). The SSA pressure in tubing decreases linearly from heel point to toe point, while the SSA pressure gradient in annulus decreases with the distance to toe point. (4). The SSA temperature in both tubing and annulus decreases with the increasing of mass fraction of air. This is because the enthalpy of air is smaller than superheated steam. (5). Increasing injection temperature can decrease the SSA pressure in both tubing and annulus by reducing SSA density and increasing frictional loss.

Based on the presented model, the SSA pressure and temperature in both tubing and annulus can be accurately predicted with the relative error less than 5%. The theoretical studies in this paper can be taken as a reference for engineers in optimization of injection parameters and provide following researchers with the very basic theory for the application of toe-point injection technique.

Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.

The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.

Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.

The severe decline of oil production has been observed in many multi-fractured horizontal wells (MFHW) within only one or two years. It is thus essential to determine production rate distribution of MFHW for improving oil production. However, available pressure-transient analysis (PTA) models of MFHW hardly consider the effect of non-uniform production rate distribution of both horizontal sections and hydraulic fractures on pressure-transient response, which may lead to erroneous results.

This paper aims at presenting an innovative approach to estimate non-uniform production rate distribution along horizontal wellbore in a relatively economical way. A novel model was proposed to better characterize flow in hydraulic fractures and horizontal wellbore. In order to better characterize pressure drops in hydraulic fractures, we first modeled fluid flow in fractures with finite conductivity by two parts, variable-mass-linear flow for fluid far from wellbore and radial flow for fluid near wellbore. Meanwhile, horizontal wellbore with finite conductivity was divided into multiple horizontal sections, and each section is considered as a cylindrical source. As a result, a semi-analytical solution was developed. We further compared it with numerical model to verify the accuracy. A new flow regime (the second radial flow) is discovered and behaves as a flat on pressure derivative curves. It would lead to erroneous results if the new regime is regarded as pseudo-radial flow.

Case study indicated that the production rate distribution obtained by the model proposed in this paper match well with production logging test (PLT), which validated the accuracy of the proposed approach and explored the feasible application in well performance evaluation of MFHW. In addition, operators could make reasonable decisions to improve well performance based on the evaluation results.

Modeling of non-Darcy flow behavior in low permeability reservoirs is significant in reservoir performance analysis. The objective of this paper is to develop a novel well testing inversion method for efficient characterization of non-Darcy flow behavior inflow velocity and pressure gradient relation at reservoir condition, which can be applied for accurateproductivity calculation and numerical reservoir simulation.

Based on extensive experimental studies, the velocity-pressure gradient relation exhibit strong non-linear flow behavior in low pressure gradient range and is then gradually converged to pseudo-linearflow behavior as pressure gradient increasing. This study introduces dynamic permeability effect (DPE) for illustrating non-Darcy flow. The numerical well testing models with DPE are furtherdeveloped for both fractured wells and non-fractured wells. Irregular grids are conducted in models for accurate calculation and enhancing computation. Then, vertical well model and fractured vertical well model are all validated by comparison with the solution proposed from Gringarten et al. (1974) and Sheng-Tai Lee (1986) respectively. Typical flow behaviors in pressure transient curve are further investigated detailedly. For vertical well model, Ι) wellbore storage, Ⅱ)transient flow and Ⅲ) non-Darcy radial flow is included. The flow regime in fractured well model can be divided into Ι) wellbore storage, Ⅱ) transient flow and Ⅲ) non-Darcy bilinear flow. The build-up test type curves show the pressure response ascended in the late time region (non-Darcy radial flow and non-Darcy bilinear flow), which indicates the effect of non-Darcy flow in the reservoir. And the larger magnitude of pressure response ascended, the more obviously the non-Darcy behavior was. Therefore, history matching of pressure transient in the late time region has an important impact on inversion result of velocity-pressure gradient curves.

Inversion method is proposed with a five-step workflow. First, linear functions, piecewise functions or continuous functions are employed to capture the non-linear behavior in low pressure gradient range. Second, the interpreted parameters are determined from well testing model and approximation function. Third, thepredicted pressure is calculatedby proposed models and calculation convergence must be fulfilled. Fourth, the coefficients of the proposed function are treated as optimization parameters that are determined by matching the pressure data using Levenberg-Marquardt optimization procedure. Consequently and finally, an accurate velocity-pressure gradient relation is established to characterize non-Darcy flow behavior in low permeability reservoirs. The productivity calculation and numerical reservoir simulation can also be done in further works.

The practicality and efficiency of the proposed methodare illustrated in synthetic case studies. First, we demonstrate the function selection process. Linear, piecewise, and continous functions are all used to make pressure history matching for function optimization. And then the fluid flow behaviorson the reservoir scaleare characterized by normalizing the velocity and pressure gradient curvesfromsingle-well analysis. With comparison to the traditional approach, we comfirmedthat the curve of flow behavior, which is obtained from well testing method, performs better in production history matching.