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Abstract Operative and economical optimization of hydraulic fracture stimulation designs requires accurate reservoir description. For unconventional tight gas reservoirs is it commonly difficult obtain reliable results from conventional build up analysis after flow testing a well because the time required to reach the IARF (Infinite Acting Radial Flow) could be much longer than normal rig time operations will practically allow. In many cases the impossibility of the well to produce after perforation makes the scenario even worst. Mini-Fall-Off injection test is economical and efficient technical solution to solve this problem providing an excellent starting point to understand unconventional plays and optimize the entered process of hydraulic fracturing technique. The scope of this work is to present an optimal operative processes which allow understand how, when and where is recommended apply this technology giving a key point to optimize the hydraulic fracture stimulation. Following a theoretical description to this new methodology is provided. In addition, this work includes a detailed guideline for planning execution and interpretation of the falloff pressure to obtain reliable reservoir transmissibility, reservoir pressure and closure pressure. Finally, the results of two cases were evaluated and it was determined that a simple field implementation could be adopted as a standard to be used in conventional pre-frac pumping procedures. Introduction During the last sixty years the main role of hydraulic fracturing technology was changing as a result of necessity and theoretical knowledge. The concept of "Fracturing to Past Damage" (1945–1975) found the main application on mili-D environments and was the first concept to understand how the frac works. On the 80' the concept of "Massive Hydraulic Fracturing" (1975–1990) was developed with great results for tight gas reservoirs. For medium and high perm reservoir "Tip Screen Out" technique seems to be the best solution from the 90' up to now. In the 2000 year unconventional reservoir start extensively treated with "water Frac" techniques. Near future of hydraulic fracturing is growing as a merge between reservoir engineering and stimulation engineering and this is main reason to understand that each shut it, after production or injection, with or without fracture in which is possible reach pseudo radial flow could gives good approximation of some reservoir information as permeability and pressure. The main parameter to optimize hydraulic fracture is the reservoir permeability almost never known for unconventional reservoirs.
Early in the development of unconventional reservoirs, the industry had little choice but to rely on the toolsets handed down from decades of conventional engineering practices. Later, new tools would be crafted in the hopes of better fitting the unconventional paradigm. This presents a choice to the technical community—rely on a traditional and proven method, or one designed for the unconventional system but less tested? Recently, many hydraulic fracturing engineers have been asking themselves this question when it comes to the diagnostic fracture injection test (DFIT). That includes myself, and the journey I took to find an answer culminated in a technical paper (SPE 206239) that was presented at the 2021 SPE Annual Technical Conference and Exhibition. What follows are some of that paper’s key findings which are being shared with the intent to further the discussion on best practices for those challenged with interpreting unconventional diagnostics. The paper utilizes the concept of permeability to validate traditional minimum stress interpretations across multiple reservoir conditions by comparing DFIT fracture closure time permeability estimates with core, pressure buildup, after-closure pressure, and rate transient analysis. This author was able to further support the results by the integration of a wide range of diagnostic technologies such as fiber optics, microseismic, and, among others, DFIT numerical inversions shared through eight case histories. Diagnostic Injections, a Long History Made Short One of the few ways to begin a conversation with a reservoir is by pumping treated fluid at fracturing rates and analyzing how the pressure falls off with time after the injection is stopped. The language for such dialogue and information exchange is formed by the dimensionless time function called “G-function” and was introduced by Ken Nolte in 1979. Nolte’s innovative postulations allowed our industry to determine the expected frac geometry, its conductivity, the formation flow capacity, and the optimum hydraulic fracture design as well as the means necessary to place the treatment. Recently introduced into industry literature is the proposed fracture closure pressure interpretation based on the fracture compliance method, interpreting an earlier, higher-stress estimation than estimates from well‑established methodologies. The practitioner is now faced with the dilemma of finding out which fracture closure interpretation technique is correct since this has a profound impact on how fracture geometry is modeled and optimized. To answer this question, a multibasin analysis of pre-frac tests from the Russia, North Sea, Europe, North Africa, and South America regions was undertaken.
- South America > Argentina (0.30)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Russia (0.25)
- (6 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract In tight reservoirs development such as shale gas it is important and yet difficult to predict the size and orientation of the drainage area around a hydraulically fractured well. Often the drainage area is determined by near-well fractures. Diagnostic fracture injection test (DFIT) is an effective way of predicting many reservoir parameters. However, it is challenging to uniquely interpret fractures' geometry, dimension and spacing. A forward model is desired to correlate the DFIT responses with different fracture configurations and the associated drainage area. We present a 2D model that couples fluid flow with geomechanical deformations in hydraulically fractured reservoirs by solving Biot's equation. Both fluid pressure/velocity and deformations are solved on a finite element mesh. Fracture space is distinguished from the rest of the matrix by high porosity/permeability and low elastic strength. The FEM mesh is adaptively refined at the fractured area to allow the fractures to be reasonably thin and arbitrarily spaced. Pseudo time iteration is applied to seek for convergence between fracture opening/closure and fluid pressure changes. DFIT is simulated with the new numerical model with a single (bi-wing) fracture case and a complex fracture case. The complex fracture case is made by adding transverse fractures to the two wings of a single fracture. The numerical results reveal pressure changes of reservoir fluid due to matrix and fracture deformations as well as due to fluid leak-off. The model is able to generate synthetic well pressure data that show all the type curves given by analytical DFIT theory. The complex fracture case results in pressure transient such that the flow regime rapidly evolves into pseudo-radial flow. For idealized bi-wing fracture cases, this model is consistent with existing analytical tools for DFIT interpretation. The advantages of this model are the ability to implement complex fractures, and the ability to extend to 3D for non-vertical fractures (briefly mentioned in the appendices). Synthetic DFIT data from the model developed in this study has been compared to a field example from a shale gas reservoir. The discrepancy between the model result and field example suggests that some special constitutive law is needed for the modeled fracture areas to appropriately capture the real fracture closure process. Introduction When a well is subjected to production or fracturing injection, the fluid flow is likely accompanied by the solid deformation. In most cases of conventional reservoirs, the initial pore volume is much larger than the volume changes that are caused by the matrix strain with competent rock grains. For this reason, the fluid flow is often modeled independently without coupling with deformation. In the cases of tight and shale gas reservoirs however, the pore volume is comparable to the strain caused volume changes. The fluid flow modeling then needs to be coupled with the solid deformation. We present our work on modeling a hydraulically fractured reservoir subjected to production or injection, where the fluid and solid are coupled by solving Biot's equation. The model is capable of generating synthetic well test data that show all the characteristic type curves given by the analytical DFIT theory. The paper is organized as follows:
- Asia (0.46)
- North America > United States (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.75)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Numerical Simulation of DFITs Within a Coupled Reservoir Flow and Geomechanical Simulator - Insights Into Completions Optimization
Ji, Lujun (Anadarko Petroleum Corporation) | Sen, Vikram (Anadarko Petroleum Corporation) | Min, Kyoung Suk (Anadarko Petroleum Corporation) | Sullivan, Richard (Anadarko Petroleum Corporation)
Abstract A novel DFIT simulator comprising a 3D hydraulic fracturing model seamlessly coupled within one software with reservoir flow and geomechanical modeling is described and used to numerically analyze DFITs in unconventional reservoirs. This workflow involves history matching treatment or injection pressures (fracture propagation) and shut-in (fracture closure) pressures consistent with 3D growth of hydraulic fractures in the presence of pressure dependent leak-off. These are the same fundamental processes which characterize Dynamic Stimulated Reservoir Volume or DSRV growth (Sen et al., 2018, Min et al., 2018) and DFITs can therefore be used to get a better early prognosis on the potential of DSRV growth in a tight reservoir. This modular DFIT simulator iteratively couples a finite-difference reservoir simulation with a finite- element geomechanical modeling within one software and can therefore maintain important consistencies between fracture opening, propagation, closure and the stress dependent leak-off and permeability evolution inside the induced dynamic SRV. Both DFIT injection and closure processes are numerically modeled - and depending on which model parameters we choose to fix and which we perturb, we can preemptively estimate the potential for a successful stimulation and its possible dimensions. This estimate can be obtained at the early stages of a field /section development, before embarking on major drilling and completion campaigns, even in the absence of substantial production data. And it provides guidance for optimizing major fracturing design and well spacing. This approach is not reliant or bound by the assumptions underlying widely-used analytical DFIT analyzing methods, and is therefore more flexible and better captures the physics of stimulation in unconventional reservoirs. An early understanding of the key geomechanical metrics defining unconventional reservoir enhancement (DSRV effectiveness) allows us to build a directional relationship between fracturing parameters and post-fracture production without the need for an extended record of production trends. This speeds up the continuous learning and adaptive process of completion optimization involving pumped volumes, cluster spacing and well landing zones.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Estimation of the Half-Length of Non-Simultaneous-Closed Fracture Through Pressure Transient Analysis: Model and Case Study
Wang, Zhipeng (China University of Petroleum Beijing) | Ning, Zhengfu (China University of Petroleum Beijing) | Jia, Zejiang (China University of Petroleum Beijing) | Cheng, Qidi (Xinjiang Oil Field Company) | Zhang, Yuanxin (Heavy Oil Development Company of Petro China Xinjiang Oilfield Company) | Guo, Wenting (China University of Petroleum Beijing) | Zhu, Qingyuan (China University of Petroleum Beijing)
Abstract During water-flooding development, severe water breakthrough has been observed in fractured wells. It is essential that determine the reason for water-breakthrough to improve the performance of production wells. However, the conventional pressure-transient analysis model hardly characterizes fracture-induced pressure response and fracture half-length, leading to erroneous results. This paper aimed at present an approach to estimate the half-length of non-simultaneous fracture induced in a relatively economical way. The non-simultaneous fracture closure flow (NFCF) model was proposed to characterize flow in induced fracture. To better characterize pressure response in induced fracture, we first modeled fluid flow in fracture with variable conductivity by two-part, variable-conductivity-linear flow and low-conductivity-linear flow. At the same time, fracture closure was considered to occur twice according to the pressure response of water injection wells, and its condiction followed experimental results. As a result, a semi-analytical solution was developed. We compared it with the finite-conductivity model to certify the accuracy. A new flow regime (the non-simultaneous fracture close linear flow) was discovered and behaved as two peaks on the pressure derivative curve. It will shorten the half-length of induced fracture if the new flow regime is ignored. Case studies showed that the NFCF model matched well with field data, which validated the practicability of the proposed approach. Our results might help accurately understand the reason for the water breakthrough - enormous the half-length of induced fracture was ignored in the past. In addition, the results also have provided significant insight for the operators could make reasonable decisions, reasonable well spacing and water-flooding rate, to improve production and water injection wells performance.
- Asia > China (0.29)
- North America > United States (0.28)
- Asia > Middle East (0.28)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)