Fracture Face Skin Research Articles

Pressure transient analysis for stress-sensitive fractured wells with fracture face damage

Fracture networks improve wells’ deliverability of fluids from underground reservoirs. However, conductive fractures may lose efficiency because of fracture closure or formation damage that needs to be monitored and detected for proper reservoir management and intervention. Fracture hydraulic conductivity is a function of fracture geometry and its hydraulic aperture, which tends to degrade during operations because of fracture compaction and closure. Furthermore, pore-clogging of fracture walls (faces) results in a damaging skin zone that may reduce fracture-matrix transmissibility. Current Pressure Transient Analysis (PTA) models in the literature do not consider the interconnected combined effect of stress-dependent conductivity of fractures and fracture face skin. Modeling fracture closure without accounting for the skin effect may mislead the PTA interpretations of well performance. This work proposes a rigorous PTA model to account for fracture closure combined with fracture face skin for single and multistage hydraulic fractures with uniform and complex geometries. The solution approach is based on subdividing the domain into three flow regions, matrix, damage zone, and hydraulic fracture (HF). The proposed model is verified extensively using a commercial simulator and other less comprehensive models from the literature. The pressure response in fractured wells with stress-sensitive fractures is analyzed at early, middle, and late times. In each flow regime, we identify pressure signals to detect fracture closure by incorporating fracture closure and skin effects. Results show that the fracture face skin has a significant effect on fracture performance as it introduces an additional pressure drop that triggers an earlier and more pronounced occurrence of fracture closure. We proposed a semi-log approach to identify fracture closure for low compressible fractures and a pseudo-radial simplification to generate late-time response curves. The proposed method serves as a PTA diagnostic tool to detect fracture conductivity degradation due to fracture closure and formation damage.

Design and Application of High-Temperature Raw-Seawater-Based Fracturing Fluids

Summary Typically, water-based fracturing treatments consume a large volume of fresh water. Providing consistent freshwater sources is difficult and sometimes not feasible, especially in remote areas and offshore operations. Therefore, several seawater-based fracturing fluids have been developed in an effort to preserve freshwater resources. However, none of these fluids minimizes fracture-face skin and proppant-conductivity impairment, which can be critical for unconventional well treatments. Several experiments and design iterations were conducted to tailor raw-seawater-based fracturing fluids. These fluids were designed to have rheological properties that can transport proppant under dynamic and static conditions. The optimized seawater-based fracturing-fluid formulas were developed such that no scale forms when additives are mixed in or when the fracturing-fluid filtrate is mixed with different formation brines. The tests were conducted using a high-pressure/high-temperature (HP/HT) rheometer, coreflood, and by aging cells at 250 to 300°F. The developed seawater-based fracturing fluids were optimized with an apparent viscosity greater than 100 cp at a shear rate of 100 seconds–1 and a temperature of 300°F for more than 1 hour. The use of polymeric- and phosphonate-based scale inhibitors (SIs) prevented the formation of severe calcium sulfate (CaSO4) scale in mixtures of seawater and formation brines at 300°F. Controlling the pH of fracturing fluids prevented magnesium and calcium hydroxide precipitation that occurs at a pH value of greater than 9.5. Most importantly, SIs had a negative effect on the viscosity of seawater fracturing fluid during testing because of their negative interaction with metallic crosslinkers. The developed seawater-based fracturing fluids were applied for the first time in an unconventional and a conventional carbonate well and showed very promising results; details of field treatments are discussed in this paper.

Investigation on the transient pressure response of water injector coupling the dynamic flow behaviors in the wellbore, waterflood-induced fracture and reservoir: Semi-analytical modeling and a field case

There is growing evidence showing that water injection may induce formation fracturing around injectors in tight reservoirs. Because waterflood-induced fractures (WIFs) are not strengthed by proppants, they close gradually during the field-testing period, which results in “fracture-closure-induced” flow rate, shrinking fracture length (SFL) and decreasing fracture conductivity (DFC). In this paper, we propose a novel semi-analytical model to characterize the bottom-hole pressure (BHP) behavior of water injectors by coupling the dynamic flow in the wellbore, WIF, and reservoir. Flows between reservoir and WIF are linked through a fracture-storage coefficient and fracture-face skin factor, while flows between WIF and wellbore are coupled via wellbore-storage coefficient and choked-fracture skin factor. Perturbation theory method is deployed to include the DFC effect, and Duhamel principle is invoked to characterize flow rate changes caused by wellbore and fracture storage effects. Results show that bi-storage effects can be identified as two unit slopes in the pressure derivative curve. In the absence of extra pressure drop between wellbore and WIF, i.e., choked-fracture skin equals to zero, a prolonged storage period with a considerably large storage coefficient can be obtained. In addition, we find that SFL could cause the variable fracture storage effect while DFC may lead to the upward of pressure derivative curve at late times. Finally, the model is successfully applied in the Changqing Oilfield to validate its reliability.

Semi-analytical modeling for water injection well in tight reservoir considering the variation of waterflood - Induced fracture properties – Case studies in Changqing Oilfield, China

It is well acknowledged that water injection may induce formation fracturing in tight reservoir, and the injection well may experience shrinking fracture length (SFL) and variable fracture conductivity (VFC) during fracture-falloff period, which shows the bi-storage behavior. However, available pressure-transient analysis (PTA) models hardly consider these effects (SFL, VFC and bi-storage behavior) on pressure-transient response, which can lead to erroneous results. This paper aims at presenting an innovative approach to model the water injection wells considering the dynamic characteristics of waterflood-induced fracture (WIF).We first modeled fluid flow between reservoir and the fracture which characterized by fracture-storage coefficient and fracture-face skin factor, and flow between wellbore and the fracture which represented by wellbore-storage coefficient and choked-fracture skin factor. In addition, the effects of SFL and VFC were included by finite difference method. A semi-analytical solution was then derived to model injection well with waterflood-induced fracture (IWWIF). Finally, this methodology has been successfully applied in Changqing oilfield, China.There are six flow regimes for the IWWIF model in the tight reservoir, including wellbore-storage regime, transitional-flow regime, fracture-storage regime, the second transitional regime, linear flow regime and bilinear flow regime. Compared to current models, the bi-storage phenomenon is discovered and validated as two straight lines with unit slope in the pressure derivate curve of type plot. The WIF that closely links with the wellbore can be regarded as an “expanding wellbore”, which illustrates the reason that the “wellbore-storage coefficients” are increased by up to several orders of magnitude in a great many of water injection wells. The VFC behavior could cause the upward of pressure-derivative curve, which is generally recognized as the characteristic of closed boundary condition while the variable fracture-storage effect may occur because of SFL. In addition, the relation between matched fracture-storage coefficient and fracture length is given, which provides us another way to obtain the probable length of WIF. Finally, this new model has been successfully used to evaluate well performance and reservoir characteristics based on bottom-hole pressure (BHP) history of five field cases in Changqing oilfield, China.

Mechanically Induced Fracture-Face Skin—Insights From Laboratory Testing and Modeling Approaches

Summary In the context of this work, a new formation-damage mechanism is proposed—the mechanically induced fracture-face skin (FFS). This new mechanism results from mechanical interactions between the proppants and the reservoir rock caused by the increasing stress on the rock/proppant system during production. Proppant embedment into the fracture face and proppant crushing lead to fines production and may impair the fracture performance. To achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock/proppant systems. In this study, permeability measurements on sandstones with propped fractures under stress using various flow cells were performed, allowing localization and quantification of the mechanical damage at the fracture face. The laboratory experiments identified a permeability reduction at the fracture face of up to 90%. The mechanical damage at the rock/proppant interface began immediately with loading of the rock/proppant system and for fracture-closure stresses less than 35 MPa; the damage was localized at the fracture face. Microstructure analysis identified quartz-grain crushing, fines production, and pore-space blocking at the fracture face, causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants reduce the fracture permeability further. Numerical modeling of the rock/proppant system identified highly inhomogeneous stress distributions in the granular system of grains and proppants. High tensile-stress concentrations beneath the area of contact between quartz grains and proppants were observed, even at small differential stress applied to the rock/proppant system. These high-stress concentrations were responsible for the early onset of damage at the fracture face. Therefore, even low differential stresses, which are expected under in-situ conditions, may affect the productivity of a hydraulically fractured well.

Gas Recovery From Tight Sands: Impact of Capillarity

SummaryHydraulic-fracturing operations carried out by injecting large volumes of water cause invasion of the injected water into the formation and create a water block. The flow of gas toward the wellbore/fracture during production will result in the removal of the water block through viscous displacement, as well as evaporation, that occurs because of gas expansion over a long period of time. However, some observations from the field show that the productivity of hydraulically fractured tight gas wells improves after a period of shut-in, leading to a speculation as to whether capillary suction is responsible for the cleanup of water block that eventually leads to productivity improvement. In this work, we use laboratory-scale experiments and modeling to find that capillary-driven transport is an important mechanism that helps redistribute water within the tight gas rock sample. Without capillarity, the model underpredicts the effective gas relative permeability recovery in the laboratory sample. We also find, using simulations, that capillary transport has the effect of enhancing the overall evaporation rate of water from the rock core. The model for calculating saturation changes and the effective gas relative permeability is complete with regard to all the mechanisms, such as displacement and evaporation. This is unlike previous studies, which did not include one or the other.Field-scale-simulation study of gas flowback using the new integrated model shows that the effective gas relative permeability of the invaded zone is significantly affected by capillary suction. In the absence of capillary suction, displacement and evaporation proceed as usual, but the invaded-zone water saturation does not dissipate quickly enough. The fracture-face skin, which is a function of the effective gas relative permeability, decreases faster as the invaded zone water is redistributed because of capillary suction. The simulations show that the evaporation of water from the invaded zone is very slow because of the low gas-flow rates in the tight rock matrix. In comparison to evaporative removal of water from the invaded zone, capillary-suction removal is significantly higher and faster.A sensitivity study on fracture-face skin shows that capillary suction has a significant effect on the cleanup at low drawdowns and smaller invasion depths. At complete shut-in conditions, the invaded-zone saturation continues to dissipate because of capillary suction. This confirms the general observation and anecdotal evidence that tight-sandstone wells produce at greater gas-flow rates after a period of shut-in. The methods described in this study can be adapted to perhaps determine the duration of such shut-in periods. Additionally, the models can be used to rigorously predict gas-production rates from a fractured well, including capillary effects, without resorting to averaging concepts such as fracture-face skin.

Hydraulic fracturing stimulation techniques and formation damage mechanisms—Implications from laboratory testing of tight sandstone–proppant systems

Reservoir formation damage may seriously affect the productivity of a reservoir during various phases of fluid recovery from the subsurface. Hydraulic fracturing technology is one tool to overcome inflow impairments due to formation damage and to increase the productivity of reservoirs. However, the increase in productivity by hydraulic fracturing operations can be limited by permeability alterations adjacent to the newly created fracture face. Such an impairment of the inflow to the fracture is commonly referred to as fracture face skin (FFS). Here, we focus on mechanically induced fracture face skin, which may result from stress-induced mechanical interactions between proppants and reservoir rock during production. In order to achieve sustainable, long-term productivity from a reservoir, it is indispensable to understand the hydraulic and mechanical interactions in rock–proppant systems. We performed permeability measurements on tight sandstones with propped fractures under stress using two different flow cells, allowing to localise and quantify the mechanical damage at the fracture face. The laboratory experiments revealed a permeability reduction of this rock–proppant system down to 77% of initial rock permeability at 50 MPa differential stress leading to a permeability reduction in the fracture face skin zone up to a factor of 6. Considerable mechanical damage at the rock–proppant interface was already observed for stresses of about 5 MPa. Microstructure analysis identified quartz grain crushing, fines production, and pore space blocking at the fracture face causing the observed mechanically induced FFS. At higher stresses, damage and embedment of the ceramic proppants further reduces the fracture permeability. Therefore, even low differential stresses, which are expected under in-situ conditions, may considerably affect the productivity of hydraulic proppant fracturing stimulation campaigns, in particular in unconventional reservoirs where the fracture face is considerably larger compared to conventional hydraulic stimulations.

Fracture-Face-Skin Evolution During Cleanup

Summary There remains considerable debate about the impact of fracture-face-matrix damage on cleanup and productivity of gas wells. The impact of the Cinco-Ley fracture-face-skin factor has been studied extensively, normally with single-phase-flow examples. Two-phase-flow examples are usually limited to the impact on long-term production. This paper uses a new two-phase-flow simulator to demonstrate the impact of fracture-face-matrix damage on both fracture-treatment cleanup and fracture-face-skin evolution during cleanup and subsequent production. The simulator was validated by comparison of calculated skins with pressure-buildup simulations evaluated by use of a high-end, third-party, pressure-transient-analysis package. The study has demonstrated that fracture-face skin relative to gas flow can be calculated continually throughout a simulation of fracture-treatment cleanup and production. It was found that at lower matrix permeabilities and subsequent higher capillary pressure curves, the impact of water saturation in the damage zone becomes much more important. Specifically, the effective fracture-face skin relative to gas can be several times higher than expected on the basis of single-phase flow. Furthermore, the simulation results show that at lower matrix permeabilities, the time required to achieve a reasonable fracture-face skin relative to gas flow can require considerable production time, on the order of several weeks, even for moderate damage factors. The results demonstrate that in tight gas reservoirs (≈0.01 md and less), even a moderate amount of matrix damage in a fracture face can result in high fracture-face skins and exceedingly long times for treatment cleanup. As such, it becomes very important to minimize fracture-face-matrix damage during tight gas fracturing treatments.

Dimensions and Degree of Containment of Waterflood-Induced Fractures From Pressure-Transient Analysis

Summary It is well established within the industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected—either for voidage replacement or disposal—large fractures may be induced over time. This paper aims to provide a methodology for injection-falloff (IFO) test analysis of fractured (produced) water-injection wells. Some essential elements of IFO for fractured water injectors include the closing fracture, (early) transient elliptical reservoir-fluid flow, finite fracture conductivity, and fracture face skin. An exact semianalytical solution is presented to the fully transient elliptical fluid-flow equation around a closing fracture with finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. This solution also captures the case that during closure, the fracture is generally shrinking from adjacent geological layers under higher in-situ stress. Based on this solution, type curves of the dimensionless bottom-hole pressure as a function of dimensionless time are provided, covering both the period during fracture closure/shrinkage and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture compliance, the height of in-situ stress contrasts, fracture face skin, fracture closure time, and injection period. It is shown how the fracture length and height and the degree of fracture containment (in combination with the heights of the stress contrasts) can be derived from these types of curves. It is also demonstrated that the analyses based on the storage flow and linear formation flow regimes need to be integrated into one analysis method to obtain consistent results. Finally, the concepts developed in this paper are applied to a number of field examples, in which the dimensions and degree of containment of the induced fractures are derived from the analysis of the IFO data.

Optimization of the Productivity Index and the Fracture Geometry of a Stimulated Well With Fracture Face and Choke Skins

Summary For a given reservoir of known permeability and dimensions, the proppant mass injected to the pay determines a unique proppant number. Unique to each proppant number, there exists an optimum dimensionless fracture conductivity that exclusively determines the optimum fracture dimensions.1 Impairments affecting flow perpendicular to the fracture surface are accounted for as fracture-face-skin effect. On the other hand, flow impairment caused by a reduction of the fracture conductivity near the wellbore is called choked fracture skin. Both effects have a large influence on the productivity of a fractured well. In this work, the performance of a fractured well is calculated with a direct boundary element method. This method provides the dimensionless productivity index, and the model allows for the presence of each of the two different skin effects. The fracture face skin was found to have a significant detrimental effect on the dimensionless productivity index, even changing the character of its dependence on the dimensionless fracture conductivity. The effect of the choke skin also was found to be potentially detrimental but less complex to account for because it can be represented as an apparent reduction in the proppant number.

Evaluation of Frac and Pack Completions and Future Outlook

Summary Frac and pack introduced in the early 1990's in the Gulf of Mexico has become a well-established completion procedure aimed at enhancing the productivity of gravel packed wells. The technique consists of incorporating a "tip screenout"1 hydraulic fracturing treatment as part of the gravel packing procedure, thus stimulating the well. However, published well test data, although showing generally better productivity than classic gravel packs, presents positive skin values indicating near-wellbore damage and often questioning the existence of a fracture intersecting the wellbore. This paper quickly reviews published data and outlines a methodology which integrates the analyses of the fracture placement data and the well test data. This integration results in a more realistic modeling of the system well and reservoir and characterizes the hydraulic fracture intersecting the wellbore. It is shown that poor fracture conductivity and/or high fracture face skin damage coupled with wellbore storage can reproduce the behavior observed in well test data and commonly interpreted with a nonfractured model. The effects of additional pressure losses across the gravel pack can also be incorporated for a more realistic modeling. Field examples are discussed to illustrate the technique and a quick outlook of how completions of unconsolidated sandstones may evolve is presented.

A Simple And Rigorous IPR Equation For Vertical And Horizontal Wells Intersecting Long Fractures

Abstract A newly developed mathematical model has been used for formation damage analyses of 12 vertical wells in the naturally fractured. reservoirs of the Spraberry Trend Area, West Texas and two hydraulically fractured horizontal wells in the Daqing field, China. The use of the model has captured the characteristics of rapid decline in productivity of the Spraberry vertical wells. Comparisons between the effects of fracture face skin and fracture conductivity indicated that stress-sensitive fracture conductivity is responsible for the productivity loss of these wells. Application of the model to Daqing horizontal wells indicated that these wells should have four to five times higher oil production rates if the formation was not damaged. Introduction The Spraberry Trend Area of West Texas was discovered in 1949 and was considered the largest field in the world. The Spraberry Trend Area presents unusual problems for both primary production and waterflooding. After more than 40 years of waterflooding, the current oil recovery is still less than 150/0. A model study of a waterflood pilot in the Spraberry Trend Area indicated a NE-SW trend of the major fractures(1). A contrast of 144/1 was required for the major/minor fracture trend permeability ratio to match the pilot response. This strong anisotropic effective permeability implies the existence of well inter-connected, long natural fractures in the Spraberry reservoir. A characteristic of flow in the long natural fractures is that the pressure variation in the long natural fracture should be significantly higher than that in a hydraulic fracture or a short natural fracture. Unfortunately, no method for analyzing flow behaviour in reservoirs with long fractures is readily available from the literature. Several analytical solutions have been presented for transient flow in fractured reservoirs(2–8). Numerical models have also been developed for simulating fluid flow in fractured reservoirs(9. 10). However, it is still desirable for reservoir engineers to use steady flow equations for identification of formation damage in the fractured reservoirs. This is not only because the analytical transient flow solutions and numerical simulators are not convenient to use, but also because steady or pseudo-steady flow prevails as the dominating flow mechanism in the lifetime of most oil wells. Therefore, steady flow equations are attractive for formation damage analysis. This paper demonstrates applications of a newly developed steady-flow mathematical model for formation damage identification. This model is utilized for analyzing performance of twelve vertical wells intersecting natural fractures in the Spraberry Trend Area, West Texas and two horizontal wells with hydraulically induced fractures in the Daqing field, China. The use of the model has captured the characteristics of rapid decline in productivity of Spraberry vertical wells. The results indicate that even though high gas saturation could hinder the productivity of the Spraberry wells, the wells should still have higher oil production rates if the formation was not damaged. Comparison between the effects of fracture face skin and fracture conductivity reduction due to pressure draw down indicates that the stress-sensitive fracture conductivity is responsible for the productivity loss of these wells.