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The Staged Field Experiment (SFE) Well No. 2 is the second of four wells funded by the Gas Research Institute (GRI) for the advancement of research in fracturing and completion technology. This tight gas well is located in a lease owned by Amoco, in the North Appleby Field, Nacogdoches County of East Texas. The well is completed in the Travis Peak Formation which is a sequence of sand shale layers found from 8,000 to 10,000 ft. The permeability and porosity average approximately 0.05 to 0.08 md and 5 porosity average approximately 0.05 to 0.08 md and 5 to 9 %, respectively.
Extensive pre- and post-fracturing tests were conducted by a consortium of academic and industry participants under the direction of a main GRI participants under the direction of a main GRI contractor. These include the stress testing of 25 zones and two mini-fracturing treatments ranging in volumes up to 6550 bbls. This paper derives a closure stress profile and possible variations using these data and related field experience, and simulates the main fracture treatment using a three dimensional fracture simulator. The simulations suggest fracture width reduction (pinching) at the perforations because of the presence of a low stress perforations because of the presence of a low stress zone below and unsymmetric fracture height growth. Significant fracture height is indicated by both field data analysis and simulations. Fracture treatment design strategy is significantly affected by this occurrence, which suggests changes to common fracture design practices of many operators in the area. The simulations are compared with post-fracturing field data analysis to assess post-fracturing field data analysis to assess the resulting fracture geometry and the predictive capabilities of the simulations. Fracture design strategies are suggested for the area resulting from the experience gained from the SFE No. 2 well.
This paper presents the authors' evaluation of the data obtained from the Staged Field Experiment (SFE) Well No. 2, in the East Texas, North Appleby Field, in Nacogdoches County (Figure 1). It addresses the evaluation of stress profiling techniques, problems encountered in the complex Travis Peak sand shale sequences, and three dimensional Peak sand shale sequences, and three dimensional (3D) simulations of fracture geometry for these profiles using Terra Tek's Terra Frac simulator. profiles using Terra Tek's Terra Frac simulator. The SFE No. 2 well is the second in a series of four research wells to be drilled and funded by the Gas Research Institute (GRI) for the advancement of fracturing and completion technology in tight gas sands. The North Appleby Field includes a small number of wells on 640 acre spacing which generally produce gas at low rates with 50-100 bbls of water produce gas at low rates with 50-100 bbls of water per day. per day. The SFE No. 2 was spudded July 7, 1987 and reached a total depth of approximately 10,160 ft on August 27, 1987. The Travis Peak Formation is a tight gas sand formation with the Upper Travis Peak, which is the subject of this analysis, found from 8,000 to 9,000 ft. Pertinent data for the Upper Travis Peak are in Table 1.
Following the drilling and casing of the SFE No. 2, twenty five intervals were stress tested and a number of geophysical and micro-seismic experiments were conducted. Two mini-fracture treatments and a main fracture treatment were performed on the Upper Travis Peak beginning April 28, 1988 and concluding September 16, 1988.
To achieve credible engineering estimates of fracture geometry, fluid efficiency, and potential risks of premature screen-out, the engineer must reliably history match the observed net-fracturing pressure. Measurement of net-fracturing pressure requires first, and foremost, a reliable estimate of the formation closure stress, to which the net pressure is referred.
This paper documents both the theory and several example field applications of a novel flow-pulse closure stress determination method. The flow-pulse technique requires only small changes in fracture treatment pumping schedule that can be accomplished at little to no extra cost, yet it allows a robust estimation of formation closure stress in real time. The flow-pulse technique involves pumping a small minifrac (usually with water) and then pumping small pulses (of about 5 bbl) of fluid during the pressure decline. There is a dramatic change in pressure response when flow pulses are pumped into an open fracture vs. a fracture that is already closed.
After a brief, but disappointing, romance with purely theoretical fracture models, the industry has now acknowledged the central role of actual measured treatment data in any serious fracture analysis effort. A large segment of the industry, however, continues to use either vastly over-simplified models (mostly 2D) or denies the value of fracture analysis altogether by simply using empirically derived fracture treatment designs and procedures. A common, however mistaken, justification for the latter two approaches is that it is simply not feasible to gather the necessary data for serious (3D, real-data) fracture analysis. This paper attempts partially to address this concern with feasible data collection for real-data fracture analysis.
Real-data fracturing analysis requires the determination of the actual observed net-fracturing pressure during a fracturing treatment and then running a suitably flexible physical model of the fracturing process until the model-predicted net-fracturing pressure matches the observed net-fracturing pressure.
Summary Production from multistage-fractured horizontal wells (MFHWs) in shale reservoirs causes stress changes that further influence the conductivities of hydraulic fractures. Moreover, many shale rocks are strongly anisotropic. The objective of this study is to semianalytically model hydrocarbon-flow dynamics in reservoirs with MFHWs. The effects of stress-sensitive hydraulic fractures and shale anisotropy are considered. First, this study explores the relationship between principal-stress and pore-pressure changes in anisotropic shale. Second, an exponential correlation is further incorporated to describe the fracture conductivities vs. pore-pressure changes in anisotropic shale. The exponential correlation is validated by matching experimental data of fracture conductivities vs. effective stress. The fracture compressibility df in the exponential equation is stress-dependent rather than constant. Next, this study discretizes each hydraulic fracture into several source segments. For each segment in each timestep, pressure distribution is calculated with source/sink functions. Both the stress field and the hydraulic-fracture conductivities are updated according to the pressure distribution with the previously mentioned correlations before starting the next timestep. In addition to the constant-bottomhole-flowing-pressure condition, nonconstant bottomhole pressure (BHP) in real-field cases can also be entered for this semianalytical model. The model is validated by comparing its results with numerical simulations. A series of type curves q vs. t is generated on the basis of model calculations. The type curves are applied to investigate the effects of initial fracture conductivity Fci, initial fracture compressibility dfi, declining rate of fracture compressibility β, shale anisotropy, and the BHP profiles on MFHW transient-rate behavior. To maximize the hydrocarbon production, the BHP profile must be adjusted on the basis of fracture stress-sensitive characteristics. The semianalytical model is used to analyze two field cases with different pwf profiles under the influence of stress-sensitive hydraulic fractures.
Diagnostic fracture injection tests (DFITs) are often used to estimate formation properties such as closure stress, pore pressure, and matrix permeability. These estimations are typically based on analysis of pressure data assuming the closure of simple planar fractures in homogeneous reservoirs. These interpretations are incorrect when dealing with complex reservoir environments such as layered reservoirs with different properties and stresses. This paper investigates the impact of such complex environments on DFIT interpretation and presents a systematic method to analyze the data.
A 3-D implicitly integrated poroelastic fracture-reservoir-wellbore model is used to simulate DFITs. DFIT fracture propagation and well shut-in are simulated with implicitly computed fluid leak-off and fracture closure. The model is validated by simulating a DFIT for a homogeneous reservoir and the implicitly calculated surface pressure is interpreted to obtain the simulation inputs (stress, pore pressure, permeability, etc.). A multi-layer reservoir model is then built in the numerical simulation domain and a DFIT is simulated in the target layer. The properties and thickness of the layers are varied to analyze their impact on the observed DFIT signature.
We analyze the impact of layer thicknesses, layer stresses, pressure and permeability of each layer, stress contrast between the layers, fracture interaction with bedding planes and the rock roughness and hardness of each layer on the DFIT pressure signature. We show that the layer property variations can cause different but characteristic DFIT pressure responses. Fracture propagation into layers with different stresses induces multiple closure events in the observed pressure signature, which provides a quantitative representation of the fracture height growth. The emergence of these closure events in the pressure signature are found to be dependent on the hardness and modulus of the rock layers and the fluid communication between the closing parts of the fracture. The DFIT signature patterns are also found to correlate with the interaction of the fracture with bedding planes (cross/arrest/divert) and provide valuable insights into fracture containment.
In this work we present best practices for performing DFIT analysis in layered reservoirs. Results from simulated DFITs in layered reservoirs clearly show the effect of key heterogeneity parameters on DFIT responses. The results from this work can be used to more accurately determine reservoir closure stress, pore pressure, reservoir permeability, fracture compliance, fracture conductivity, and fracture containment in heterogeneous reservoirs.
Abstract Interaction between adjacent fractures in horizontal wells has been recognized and discussed for some time. However, the scope of these discussions has been narrow and covers a limited number of actual field situations. In this paper, effects of dynamic interactions between multiple fractures are analyzed for different operational scenarios. These include effects of passive (previously fractured), active (being fractured) and multiple active fractures. A new aspect of this study, not previously covered in the literature, is examination of fracture inclination with respect to the wellbore. Paper will show that; The effect of dynamic interaction between adjacent fractures is largest when there is small difference between magnitudes of the two horizontal principal stresses, high net fracturing pressure, and short spacing between fractures. Dynamic fracture interaction is most significant when multiple fractures are created simultaneously (e. g., in Plug & Perf completions with limited entry design). There are important basic differences between dynamic interactions caused by transverse and inclined fractures. The influence is larger with inclined fractures. In multiple fracturing treatments based on limited entry, if the created fractures are transverse, dynamic interaction may cause shorter fractures to deflect and coalesce with longer adjacent fractures, thus further accelerating their growth. Compared to a single fracture, multiple limited entry fractures in horizontal wells require higher extension pressure. However, interaction between fractures is not likely to cause a significantly higher pressure in successive pumping stages in the same well. Dynamic interaction between multiple simultaneous fractures has little impact on ISIP values between successive pumping stages. In cases of small difference between the two horizontal principal stresses and high net fracturing pressure dynamic interaction can cause fracture deviations of more than 45°. This will increase the possibility of linkage between shorter fractures with longer adjacent fractures and accelerating their growth. The results presented here are in line with actual field data. The analysis presented here differs from some existing solutions in certain critical assumptions regarding the effect of a passive fracture on the propagation of an active fracture. However, the present results are in line with actual field data trends.