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Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
ABSTRACT Using a numerical simulator, effects of proppant ramping on the quality of hydraulic fracturing treatment and production enhancement in two different formations, high-permeable oil and low-permeable gas formations, were evaluated and analyzed in this study. Proper proppant size and fracturing fluid for each zone was selected based on Net Present Value (NPV). Results showed that high leak-off coefficient (HLC) fluid with Badger Sand (12/20) and low leak-off coefficient (LLC) fluid with Arizona Sand (20/40) are best proppant sizes and fracturing fluids for high- and low-permeable zones, respectively. The results revealed that highest production rate in high-permeable zone is achieved when HLC fluid with low proppant (sand (12/20)) concentration are pumped at high injection rate (40 bpm). On the other hand, highest production rate in low-permeable zone is achieved when LLC fluid with low proppant (sand (20/40)) concentration are pumped into the formation at low flow rate (14 bpm). A total of eight stages of fracturing job, starting with a pad stage and ended with a flush stage, were simulated for each case in this study. The results demonstrated that early sand-out occurs when proppant concentration is high at the beginning of fracturing treatment operation. 1. INTRODUCTION The reservoir rock would fracture-open when a specific fluid is pumped into the targeted zone at appropriately high pressure. By continued pumping of the fluid at this sufficiently high pressure, the fluid will propagate the crack into the pay zone. A small grain of proppant such as sand 12/20 could be pumped into the crack to hold it open and create a high permeability zone. This technique is well-known as hydraulic fracturing that is popularly implemented in the oil and gas industry. Figure 1 shows the simple idea about hydraulic fracturing. Hydraulic fracturing has been one of the significant engineering techniques implemented to improve well productivity in damaged near-wellbore and low-permeability reservoirs. Improving well productivity can be achieved by creating high conductive media for fluid to flow or bypassing a damaged area by creating a conductive channel through it around the wellbore. Moreover, lengthening the channel to a significant depth to increase the productivity (Economides and Nolte, 1989). The first hydraulic fracturing procedure for well stimulation was conducted in the Hugoton of western Kansas (gas field) in 1947 (Figure 2). However, for the last decades, hydraulic fracturing has resumed to overlook low-permeability formations and economically produce hydrocarbons from unconventional reservoirs (e.g., tight gas formation) in North America.
Wei, Yunsheng (Research Institute of Petroleum Exploration and Development) | Wang, Junlei (Research Institute of Petroleum Exploration and Development) | Jia, Ailin (Research Institute of Petroleum Exploration and Development) | Qi, Yadong (Research Institute of Petroleum Exploration and Development) | Liu, Cheng (PetroChina Zhejiang Oilfield Company)
It is of great significance to optimize the design of multistage-fractured horizontal wells (MFHW) for increasing recoverable reserves. The main objective of this work is to provide a quantitative assessment of optimal decisions such as number of wells, number of fractures per well, mass of proppant and fracture dimensions. In this study, a rigorous performance simulation of multiwell pad is established to account for the interwell interference caused by varying-conductivity fractures connected to MFHW. Next, a semi-analytical approach is proposed to forecast the transient rate response and investigate the effect of fracture dimensions and completion parameters on estimated ultimate recovery (EUR). Finally, a systematic workflow that optimizes an overall economic objective is developed. The fracture design is posed as nested optimization, where the outer-optimization shell determines the number of MFHW and the number of fractures per MFHW, whereas the inner-optimization shell based on the time-dependent unified fracture design (UFD) involves the decisions on the optimal fracture dimensions. The results show that: With consideration of technical constraint, the maximum EUR would be achieved on the best compromise between fracture dimensions. In the condition of optimal fracture dimensions, EUR is monotonously increased with the increase of number of wells (nw) and number of fractures per well (nf). With consideration of economic constraint, combination of nw and nf determines the achievable recovery and cost. The best accomplishment between w and nf by balancing production vs. cost can maximize net present volume (NPV). Under both the technical and economic constraints, when Nprop is relatively lower, more wells and less short-length fractures are suggested to maximize NPV; when Nprop is higher, less wells and more large-length fractures are designed. This work enables operators to develop a better understanding of the optimum principle, and provides a theoretical guidance to obtain the optimal fracture design of multiwell pad by integrating production-estimation module, UFD module, and NPV module.
Mahajan, Sandeep (Petroleum Development Oman, Sultanate of Oman) | Behera, Chaitanya (Petroleum Development Oman, Sultanate of Oman) | Hemink, Gijs (Petroleum Development Oman, Sultanate of Oman) | Hamdoun, Lana (Petroleum Development Oman, Sultanate of Oman)
Abstract The Amin field located in South Oman is one of the PDO's major producing oil fields. The reservoir is good quality sandstone formation with average porosity of 28% and average permeability of 800 mD. Prior to 2014, the field was developed using natural depletion drive during which some parts of the field experienced significant pressure depletion. This depletion was due to combination of high production from the crestal area and the presence of a near field-wide intra baffle (L110), that restricts the aquifer response to the upper layers of the reservoir. The baffle about 2m to 4 m thick is a cemented sandstone with minor shale intercalation that has caused the vertical pressure variation across baffle L110. To arrest the field pressure depletion, water-injection was implemented since 2014, for further field development. Produced water is injected into the aquifer below the OWC of the field through 38 vertical injector wells. To achieve desired voidage replacement injection is expected with fracturing conditions using untreated produced water with injection rates > 1500 m3/day. Bottom hole pressures are at or above formation fracture pressure and decline in injectivity with time has been observed due to untreated water. Geomechanical data and modeling results were integrated with WRM activities, trials data and surveillance technologies to optimize the injection strategy for improved waterflood performance. Geomechanical data was acquired to estimate the formation fracture pressure to provide guidance on maximum allowable injection pressure in injectors with perforations closer to OWC to manage the risk of induced fracture growth. A Produced Water Re-Injection (PWRI) fracture modeling and analysis was performed to determine the potential fracture dimensions to provide input to development decisions of injection rate and perforation depth below OWC. Simulations were carried out with estimated range of formation fracture pressure, Petrophysical parameters, injection rate forecasts and expected water quality parameters e.g. TSS (Total Suspended Solids) The simulation results from the field data calibrated PWRI fracture model indicate that injection higher rates > 1500 m3/day, would result in vertical fracture growth from the injection depth. The rate of fracture growth is primarily influenced by water quality and depth of injection. Formation fracture pressure decreases with depletion therefore once the vertical fracture propagates and enters into the upper reservoir zone, fracture growth will be accelerated. Results indicated that if injection depth closer to OWC can result in short-circuiting as early as 2 years for certain field area. Higher injection rates to meet the desired voidage replacement ratio has significant impact on the field's waterflood performance. Results provided inputs to reservoir simulations and injection rate envelope for varying perforation depth below OWC. The study benefits the field to minimize risk of injector producer short-circuiting for improved waterflood management.
Abstract Currently, the oil industry is using hydraulic fracture as a tool to exploit tight and ultra-tight oil formations. In carbonates, acid fracturing is common, unlike proppant fracturing in sandsones. The main objective of this paper is to study the behaviour of HCl injected and oil flow back from a horizontal well with multi-stage acid fractures (fractured hydraulically). For a vertical well, a single acid fracture is common. The 2D fracture model and psedo-3D fracture model are incorporated in this integrated program for acid fracturing with all geomechanics and operational constraints. With five stages of fractures, post-fracture oil production from an acid fractured horizontal/vertical well is generated from this integrated model. Program is written in MATHCAD to observe the volumetric flow rate in steady-state, transient, and pseudosteady regime. ANSYS Fluent is used to carry out a computational fluid dynamics (CFD) for oil flow back along the fractures. CFD is applied to observe production rates where sequential pad fluid and acid injection is performed until the desired fracture dimensions are reached. Results from production model shows, for steady-state, production increased from 44 to 60 STB/D and from 113 to 124 STB/D with P-3D-C and 2D-PKN-C fracture model respectively. CFD simulation is performed using a viscous model with gravitational and turbulent effects and the results show an increase in radial turbulence at the outlet of the fracture. The absolute pressure exerted on the walls is 1700 psi and the flow velocity increased from the tip at 39.4 ft/min covering a fracture length of 500 ft in both steady-state and transient flow. This paper investigates the effect of acid fracturing on oil production using a predetermined fracture model and dimensions. The flow characteristics are challenged in multi-stage fractures in horizontal and vertical well. The outcome of CFD will assist in upscaling the simulation to a 3D model with field values from existing wells for validity. A further development with fracture simulation are carried out for vertical and horizontal fracture to understand the deformation behavior on the predetermined zone. This paper will contribute to advanced well stimulation techniques of acid fracturing that are representative of actual field applications.
Abstract Multi-stage hydraulic fracturing is considered as a solution to low-productivity wells when the reservoir properties are not good enough to produce oil or gas naturally. The Inflow Performance Relationship (IPR) is the most common method used to evaluate well productivity. Many models have been introduced to estimate the IPR for horizontal wells. However, a significant error will result when they are applied for fractured horizontal wells. This work introduces a new IPR model to estimate gas production rates from multi-stage hydraulically fractured horizontal gas wells at different well pressures. A single-horizontal-well simulation model was built to generate the production data, and several scenarios were created by changing different parameters, such reservoir permeability anisotropy and fracture properties (fracture dimensions, conductivity, and the number of fractures) to determine the parameters that significantly affect gas production rates from such wells. After the effective parameters were determined, 70% of the resultant data was used to develop the new IPR model using nonlinear regression techniques, while 30% of the data was used for testing. Afterward, a statistical study was performed to evaluate the proposed model to ensure its accuracy in estimating gas production rates using different statistical means, such as R-squared, mean percentage error, variance, and standard deviation. The term dimensionless conductivity was introduced to simplify the model. This term is a combination of reservoir permeability, fracture half-length, and fracture conductivity. The gas production rate was found to be a strong function of the ratio between vertical and horizontal permeability, the number of fractures, and fracture conductivity, while the height of the fracture and the half-length had no significant effect on the dimensionless IPR curve. The new model showed an excellent performance in estimating gas production rates for hydraulically fractured horizontal wells with a mean percentage error of 3.06% and R-squared of 0.9966. This study introduced a new simple and reliable IPR model that accurately estimates the gas production rates from multi-stage hydraulically fractured horizontal gas wells at different flowing bottom-hole pressures.
Abstract Unconventional assets are crucial to the overall economic production of hydrocarbons. With the industry-wide trend of optimizing well spacing comes an increase in “frac hits”, i.e., adverse impacts on producing wells from stimulating a nearby well. Although in-zone frac hit events do not necessarily pose an environmental problem, data shows that existing, producing wells can be negatively impacted in a number of ways. Producing wells can be harmed when the pressure wave created during the hydraulic fracturing process is strong enough to cause pressure spikes or sand loading, either directly through fracture/fracture interactions or indirectly due to the propagating pressure wave reaching a nearby well drainage boundary with enough energy to cause damage. Consequently, finding ways to minimize the effect of fracture hits is currently a major focus in the oil and gas industry. In this paper, we consider an approach to mitigating frac hits that can be applied when initially performing acreage planning by ensuring sufficient well spacing during pad planning, or at stimulation time by limiting fracture lengths so that fractures do not directly interact with nearby producing wells. Introduction Drilling, completing and stimulating unconventional wells requires significant capital investment. Because unconventional assets are becoming increasingly more important, there is an industry-wide tendency to maximize acreage production by optimizing well spacing in unconventional reservoirs. However, reduced well spacing has led to “frac hits”, here defined as unwanted interactions between a hydraulically stimulated well and a nearby producing well. Given the amount of in-fill drilling currently afoot in the industry (Vidma et al. 2019), and the number of future horizontal wells forecasted to be fractured (Cook et al. 2016; Perrin, et al. 2016; Cook et al. 2018), the issue of frac hits has become of significant concern. Field data demonstrates that producing wells can be negatively impacted in several ways. For example, the pressure wave created during the hydraulic fracturing process can interact with the existing well drainage boundary either directly or indirectly. Direct interactions include fracture/fracture interactions such as strong pressure spikes or fracture clogging, and may include interactions via fracture networks as well. Indirect interactions may occur when the hydraulic stimulation-induced pressure wave propagates through the porous subsurface and reaches a nearby well with enough energy to cause damage. Damages can occur to downhole artificial lift equipment, through sand loading or pressure spikes, or manifest as production re-routing from one well to another or as production re-distribution within a well.
ABSTRACT: A general first principle framework has been presented to calculate pressure transfers between hydraulic fractures in a nearly impermeable reservoir. The methodology is derived from linear poroelasticity and defines the initial and boundary conditions to effectively construct a boundary value problem describing the stress changes in the reservoir surrounding the hydraulic fracture. The pressure transfers are largely governed by the dimensions and relative position of the fractures. The resulting pressure transfer function may be leveraged to estimate hydraulic fracture dimensions and fracture growth rates, based on field pressure observations. Here, the proposed computational framework serves as a Digital Twin to the real-world, subsurface asset. To serve as an accurate digital representation, the simulations need to be development specific and based on the actual subsurface geometries. A model problem demonstrates the applicability for a pad with multiple landing zones.
In recent years, as well-spacing and infill drilling have become central to unconventional reservoir development, the analysis of offset pressure data has attracted increased attention. Significant advances have been made towards understanding hydraulic fracture “hits” and fracture extensions, (King, 2017), (Roussel, 2017), and (Seth, 2018), as well as poromechanic pressure interference during treatment (Daneshy, 2012), (Kampfer, 2016), (Fu, 2019), and (Spicer, 2018). To truly capitalize on offset pressure monitoring as a cost-effective completion diagnostic, a process to analyze field data that is reproducible and scalable is required to deliver reliable results, which support systematic, scientific method-based testing of completion design.
A novel approach proposed by (Spicer, 2018) describes such a process by leveraging validated theory from the domain of mathematical optimization, in combination with the construction of a digital twin. The Digital Twin is comprised of a computational physics model describing the pressure interference during hydraulic fracturing of a real-world, multi-well pad. (Kampfer, 2016) published a first version of a digital twin for modeling hydraulic fracture induced poroelastic behavior. This work set the foundation for simulating transient pressure responses by explicitly modeling the three-dimensional primary fracture geometries of both treatment and monitoring fractures. Their approach uses a fully coupled poromechanical Finite Element Analysis implementation to build the predictive model required for pad-specific scenarios.
Wang, Junlei (PetroChina Research Institute of Petroleum Exploration and Development) | Wei, Yunsheng (PetroChina Research Institute of Petroleum Exploration and Development) | Luo, Wanjing (China University of Geosciences, Beijing)
Summary The classical optimization design dependent on a single‐fracture (SF) assumption is widely applied in performance optimization for hydraulically fractured wells. The objective of this paper is to extend the optimal design to a complex fracture network to achieve the maximum productivity index (PI). In this work, we established a pseudosteady‐state (PSS) productivity model of a fractured horizontal well, which has the flexibility of accounting for the complexity of fracture‐network dimensions. A semianalytical solution was then presented in the generalized matrix format through coupling reservoir‐ and fracture‐flowing systems. Subsequently, several published studies on the PSS productivity calculation of a SF were used to verify this model, and a 3D transient numerical simulation of an orthogonal fracture network was used to perform further verification. We show that results from our solutions agree very well with those benchmarked results. On the basis of the model, we provide a detailed analysis on the productivity enhancement of the fracture‐network/optimization work flow using unified fracture design (UFD). The results show the following: The PI is determined by fracture conductivity and complexity (network size, spacing, and configuration), and it is a function of fracture complexity and conductivity when the influence of proppant volume is not considered. Under the constraint of a given amount of proppant known as UFD, the maximum PI would be achieved when the best balance between network complexity and conductivity was obtained. It is more advantageous to minimize fracture complexity by creating relatively simple‐geometry fractures with smaller network size and larger fracture spacing in the condition of small and intermediate proppant numbers. It should be the design goal to generate a complex network by creating relatively complex‐geometry fractures with larger network size and smaller fracture spacing in the condition of a large proppant number. Increasing fracture complexity could reduce the optimal requirement of fracture conductivity. The proposed approach can provide guidance for a network‐hydraulic‐fracturing design for an optimal completion.
Abstract Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties. Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk. Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data. Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency. Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within Gharif formation.