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ABSTRACT: The formation parting pressure of a reservoir is affected by current reservoir pressure, original reservoir stresses, formation geomechanical properties such as Young's modulus and Poisson Ratio, and injection practices including water quality and temperature difference between injected water and reservoir temperature. These parameters are determined by different methods with different level of confidence. Monte Carlo simulation is used to study the distribution of the formation parting pressure for given distributions of each random variable. During water flooding process, the dynamic injectivity is determined by considering all of parameters. With the knowledge of parting pressure distribution and dynamic injectivity, a water injection project could be better managed. This paper presents a stochastic procedure to determine the formation parting pressure for a water injection well. Using the determined parting pressure, the procedure to determine the injection profile of the relationship between the pump pressure and injection rate are proposed. The field application is on a detailed technical discussion of water injection practice in an oil field in Gulf of Mexico, which adopted a method of micro-fracturing to enhanced oil recovery. From given formation properties, our calculated parting pressure is consistent with actual treatment. The determined parting pressure was suggested to use to keep the integrity of the reservoir container.
Water injection is arguably the most often used improved oil recovery technique. Field practices show that injectivity of a water injection well usually declines with injection time. To maintain needed injection rated, it often requires increasing injection pressure, which potential induces hydraulic fracturing when the injection pressure is above the formation parting pressure. Sometimes the fracturing can occur inadvertently, which could cause many undesirable effects such as matrix bypass event, short-circuiting water injection, and offsetting production well. Therefore, a thorough understanding of the formation parting pressure during water injection is critical for reservoir management.
The single-well chemical-tracer test (SWCTT) has been applied for decades with much success in estimating residual oil saturation in near-wellbore locations. The information obtained from an SWCTT is critical for designing a method for enhanced oil recovery (EOR). However, a key assumption in the conventional SWCTT is that only single-phase (water) is mobile. In reality, this is often not the case, and significant error can occur if the conventional SWCTT analysis method is used when multiple phases flow at the same time. The objective of this study is to improve the accuracy and precision of SWCTT interpretation in a multiphase-flow condition.
In this paper, we propose an innovative procedure of SWCTT and modify the method of moment (MOM), aiming at the two-mobile- phase condition. In the development of the algorithm, a ratio parameter is introduced to adjust the calculated swept-volume difference between the conservative tracer and the partitioning tracer. In addition, a mixture injection of oil and water is required, instead of the pure-water injection in an SWCTT.
The proposed approach is verified through numerical simulation on synthetic cases with known input parameters. The model being simulated consists of a radial-flow regime with a single vertical well in the center. The input oil saturation varies from 0.1 (immobile oil saturation) to 0.9. Our results show that the saturation estimated from the modified MOM matched the simulation input data, indicating that our approach is able to capture the saturations under two-mobile-phase condition. Moreover, the modified MOM can also be applied in single-mobile-phase condition and can improve the accuracy of conventional MOM.
Oil production decline and excessive water production are prevalent in mature fields and unconventional plays, which significantly impact the profitability of the wells and result in costly water treatment and disposal. To seek for a sustainable development of those wells, reducing the operation cost and extending their economic lives, this paper presents a method of synergistic production of hydrocarbon and electricity, which could harvest the unexploited geothermal energy from the produced water and transfer heat to electricity in the wellbore. Such method is cost-effective, since it does not require any surface power plant facility, and it is replicable in numerous wells including both vertical wells and horizontal wells. By simultaneous coproduction of oil and electricity, the value of existing assets could be fully developed, operation cost could be offset, and the economic life of the well could be extended.
This recently proposed method incorporated thermoelectric power generation technology and oil production. In this method, electricity could be produced by thermoelectric generator (TEG) mounted outside of the tubing wall under temperature gradient created by produced fluid and injected fluids. The aim of this paper is to illustrate the economic practicability of oil-electricity coproduction by using thermoelectric technology in oil wells based on previously proposed design. We examined the technical data of high water-cut oil wells in North Dakota and collected required information with respect to performance thermoelectric power generations. Special emphasis was placed on the key parameters related to project economics, such as thermoelectric material, length of TEG and injection rate. Sensitive studies were carried out to characterize the impact of the key parameters on project profits. We showed that by simultaneously production of oil and electricity, $234,480 of additional value could be generated without interfering with oil production.
The proposed method capitalizes on the unexploited value of produced water and generates additional benefits. This study could provide a workflow for oil and gas operators to evaluate an oil-electricity coproduction project and could act as a guidance to perform and commercialize such project to balance parts of the operation cost and extend the life of the existing assets.
Wu, Xiaye (The University of Oklahoma) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Yin, Fei (Chengdu University of Technology) | Teodoriu, Catalin (The University of Oklahoma) | Wu, Xingru (The University of Oklahoma)
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient.
Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.
Flow pattern of a multi-phase flow refers to the spatial distribution of the phase along transport conduit when liquid and gas flow simultaneously. The determination of flow patterns is a fundamental problem in two-phase flow analysis, and an accurate model for gas-liquid flow pattern prediction is critical for any multiphase flow characterization as the model is used in many applications in petroleum engineering. The objective of this study is to present a new model based on machine learning techniques and more than 8000 laboratory multi-phase flow tests.
The flow pattern is affected by fluid properties, in-situ flow rates of liquid and gas, and flow conduit geometry and mechanical properties. Laboratory data since 1950s have been collected and more than 8000 data points had been obtained. However, the actual flow conditions are significantly different with any laboratory settings. Therefore, several dimensionless variables are derived to characterize these data points first. Then machine learning techniques were applied on these dimensionless variables to develop the flow pattern prediction models. Applying hydraulic fundamentals and dimensional analysis, we developed dimensionless numbers to reduce number of freedom dimensions. These dimensionless variables are easy to use for upscaling and have physical meanings. We converted the collected data from actual laboratory measurement to the variations of these dimensionless variables. Machine learning techniques on the dimensionless variable significantly improved their predictive accuracy. Currently the best matching on these laboratory data was about 80% using the most recently developed semi-analytical models. Using machine learning techniques, we improved the matching quality to more than 90% on the experimental data.
This paper applies machine learning techniques on flow pattern prediction, which has tremendous practical usages and scientific merits. The developed model is better than current existing semi-analytical or classical correlations in matching the laboratory database.
Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods.
The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology.
This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units.
This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.
Xu, Ziyi (University of Oklahoma) | Yin, Fei (University of Oklahoma, Chengdu University of Technology) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Wu, Xingru (University of Oklahoma)
Transverse hydraulic fracturing along the horizontal well segment is the key technology for developing the low permeability shale reservoir, and the efficiency of the horizontal drilling and completion is growing. While concurrent with advancing D&C technologies, the well bore integrity, particularly on production casing deformation is worthy of study. To reveal the casing deforming mechanism, a 2D finite element model of injection-induced deformation under hydraulic fracturing is established in this study. The poro-elastic constitutive relation is employed to analyze the changes of stress and flow fields during hydraulic fracturing. The cohesive zone model is adopted to simulate fracture growth. Results indicate that hydraulic fracturing would cause formation deformation and natural fracture slippage. The casing failure mechanism is identified as shear deformation induced by the slippage of shear fractures during hydraulic fracturing. This study supplies an easy method to forecast formation/wellbore response and casing deformation under hydraulic fracturing.
Due to the increasing energy demand, the development of unconventional resources in extremely tight formation is becoming more and more critical. The advanced drilling and multistage hydraulic fracturing technologies in horizontal well have made it possible to develop extreme low permeability unconventional formations (Yuan et al., 2017; Sharma et al., 2017). Field practices have shown that the large scale hydraulic fracturing could compromise the well integrity through casing deformation or failure, which results in the premature abandonment of well completion and low well productivity and ultimate recovery. In Pennsylvania, unconventional wells showed a six times higher integrity issue occurring rate compared to the same period conventional wells (Ingraffea et al., 2014). In another case, the failure rate of casings in shale gas wells is as high as 31.2% during hydraulic fracturing in ChangNing and WeiYuan, China (Chen et al., 2017). In these regions, the casing deformation or failures occur frequently during the multi-stage hydraulic fracturing process, which significant impacted later operations and production efficiency.
Sustaining casing integrity is one of the challenges of shale gas wells. Davies et al. (2014) gave an overview on the oil and gas wells and their integrity, especially for shale and unconventional resource exploitation based on data from all over the world. Daneshy (2005) attributed casing failure to a consequence of large formation deformation, including compressive, tensile and shear stresses in the formation. Using downhole tilt data in an observation well, Wang et al. (2015) identified that the local buckling, connection failure and shear failure are the main failure modes. Lian et al. (2015) concluded that some casing failures were the joint result of rock property change, asymmetric treatment zones and stress field redistribution using finite element modeling. The heterogeneity severity of stress field increases significantly. Dusseault, Bruno, and Barrera (2001) attributed the dominated casing-deformation mechanisms to localized horizontal shear at weak lithology interfaces and injection intervals. Last et al. (2006) studied the casing deformation in a tectonic setting situated in foothills of the Andes. Analysis of sonic caliper logs from wells showed that the deformation accompanying formation movement results in ovalisation of the pipe rather than local shearing. The above literature survey shows that the fundamental mechanisms of casing deformations are multitude and some of them are contradictory to each other. Therefore, it is important to study the casing deformation, particular in shale formation from a fundamental and integrated manner.
ABSTRACT: Hydraulic fracturing induces formation response accompanying with complex fracture network. The extreme formation response potentially causes unfavorable consequences including wellbore instability, casing failure and fault reactivation etc. It is significant to predict formation behavior induced by hydraulic fracturing for a safe and efficient stimulation. Based on rock mechanic, experiments and micro-seismic events, fracture slip is identified, and casing failure mechanism is revealed. To quantitative evaluation, a hydro-mechanical coupled model is established to predict formation behavior under hydraulic fracturing. The hydraulic and natural fractures are embedded in formation with cohesive zone model. The pore pressure, fracture propagation, effective stress, and deformation of formation are analyzed. Results indicate that the proposed hydro-mechanical coupled model can predict the fracture growth and formation behavior under hydraulic fracturing. The pressurized zone is consistent with the fracture propagation. The effective stress along the wellbore fluctuates with time and space, which becomes lower at the location around fractures. The horizontal and vertical displacements along the wellbore increase during injection and decreases after shut-in. Especially, a distinct shear slip arises at the crossing point between the inclined natural fracture and horizontal wellbore. The well barrier will be subjected to the tensile and shear loads. The research findings can be applied to predict formation response and assess well integrity under hydraulic fracturing.
The multistage hydraulic fracturing treatment is widely used in long horizontal wells to maximize the stimulated reservoir volume (SRV) for developing low-permeability resources economically. Hydraulic fracturing can cause the initiation and propagation of hydraulic fractures (HF) and their connection with natural fractures (NF). Hence, a complex fracture network forms and the permeability of reservoir rises. Meanwhile, this stimulation can lead to the changes of pore pressure, in-situ stress field and rock property. So, formation deformation, fault reactivation and seismicity could occur.
The drastic formation response during hydraulic fracturing has posed a great challenge to formation/well integrity and HSEE potentially. Hundreds of micro-seismic events occur in each stage fracturing and the distribution is dispersed (Lin and Ma, 2015). Hydraulic fracturing triggered the major injection-induced earthquakes in western Canada. The largest seismic event (moment magnitude 3.9) occurred several weeks after injection along a fault (Bao and Eaton, 2016). Guglielmi et al. (2015) directly measured fault slip induced by injection into a fault and found the aseismic slip was about 4∼10 μm/s.
Han, Lihong (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Wang, Hang (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Wang, Jianjun (Tubular Goods Research Institute of CNPC and State Key Laboratory of Performance and Structural Safety for Petroleum Tubular Goods and Equipment Material) | Xie, Bin (Xinjiang Oilfield Company of CNPC) | Tian, Zhihua (Xinjiang Oilfield Company of CNPC) | Wu, Xingru (University of Oklahoma)
Summary An oil field in Xinjiang, China, experienced a casing failure rate of 15 to 30% in thermal wells, mainly relating to inadequate protocols of casing design. This paper presents a new strain-based casing-design method. New material parameters are proposed to build safetyevaluation principles throughout the service life of a thermal well. In addition, a gas-tight thread joint is applied to prevent steam leakage that otherwise would cause a large transversal stress between different formations, and result in slip deformation of the casing string. Field practices have shown that the new method's fitness works better for thermal wells than previously used methods. Introduction The cyclic-steam-stimulation (CSS) process has been widely used to develop heavy oils. The CSS process comprises three stages: steam injection, soaking, and oil production. In the steam-injection stage, casing expands and is subjected to compression as a result of axial constraints from both cement and the formation because of their thermal expansions (Wong and Yeung 2005).