Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.
In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.
A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.
Marginal economics underscores the importance for accurate estimation of production profile and expected ultimate recovery or EUR in unconventional resources. While the Arps family of type-curves and the stretched-exponential model appears to yield reasonable estimation of EURs, all insufficiently explain the intrinsic behavior of unconventional reservoirs. This study introduces and applies a new semianalytical approach for estimating production profile and EUR, validated by numerical simulations and verified by field data for unconventional gas and oil reservoirs.
We obtained analytical solutions by considering concentric compressibility elements, analogous to electrical capacitors, in series using the continuity equation to obtain production from conceptual geobodies. This configuration mimics decreasing contributions from a series of concentric reservoir segments into the well with increasing distance from the stimulated-reservoir volume or SRV. The analytical formulation captures production behavior of early-time and SRV-dominated flow patterns, leading to good estimation of expected-ultimare recovery or EUR.
Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting.
We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko's stretched-exponential method, (c) Ilk et al's power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated-reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes.
The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.
Many equiprobable solutions exist while history matching a reservoir's performance, given the ill-posed nature of the inverse problem. To mitigate some of the uncertainty issues stemming from the initial static reservoir description, this study shows how continuous learning evolves when a slate of analytical tools are used while interpreting real-time surveillance data. The combined approach involving the use of analytical tools in conjunction with numerical simulations helps understanding reservoir performance, which, in turn, allows insights into history matching. Specifically, we demonstrate the use of various analytical tools to learn about (a) time-dependent behavior of both producers and injectors with rate-transient analysis to assess an evolving waterflood, (b) reservoir heterogeneity with pressure-transient analysis, (c) degrees of time-variant injection support with the reciprocal-productivity index, (d) injector-producer connectivity with the capacitance-resistance model, and (e) real-time injection-well behavior with the modified-Hall analysis.
The benefits of collective use of analytic tools demonstrate that they should be used either simultaneously or preferably before undertaking a detailed numeric flow-simulation study, particularly where real-time data are being gathered. In particular, the lack of performance match for the entire history with a numerical model becomes transparent when the learning from analytical tools is juxtaposed. This understanding paves the way for much improved learning of reservoir plumbing.
This study expands upon the use of modified-Hall analysis to discern the characteristics of a high-permeability channel. Briefly, the modified-Hall plot uses three curves involving improved Hall-integral and the two derivatives, analytic and numeric. Ordinarily, the derivative curves overlay on the integral curve during matrix injection, but separates lower when fracturing occurs. This work presents a method to identify and characterize high-conductive layers or channels between injector and producer pairs with the modified-Hall analysis. The distance separating the integral and derivative curves provides the required information to quantify channel properties. A simple analytical solution is presented for transforming the separation distance into channel permeability-thickness product.
The analytic derivative is based on the radial-flow-pattern assumption and the numeric derivative is correlated to the pressure response. Therefore, a comparison of these two curves reveals clues about the maturity of a waterflood at a given time. Several simulated examples verified the channel-property-estimation algorithm and identified the distinctive derivative signatures for channeling and fracturing situations. This methodology is also useful for identification of wormhole propagation during sand production in unconsolidated formations.
The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined the Wafra Ratawi grainstone for which production extending for 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity, and overall effect have been elusive. In this study, we find that a limited number of total fractures affect production characteristics of the Ratawi reservoir. Although fractures occur throughout the Wafra field, fracture-influenced reservoir behavior is confined to the periphery of the field where the matrix permeability is low. This work suggests that for the largest part of the field, explicit fractures are not necessary in the next-generation Earth and flow-simulation models.
The geologic fracture assessment included seismic fault mapping and fracture interpretation of image logs and cores. Fracture trends are in the northeast and southwest quadrants, and fractures are mineralized toward the south and west of the field. Pressure-falloff tests on some peripheral injectors indicate partial barriers, and most of these wells lie on seismic-scale faults in the reservoir, suggesting partial sealing. A few wells show fractured-reservoir production characteristics, and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, however, to attest to the notion of localized fracture response. The spatially restricted fracture-flow characteristics appear to correlate with fracture or vug zones in a low-permeability reservoir.
Presence of fracture-flow behavior was tested by constructing the so-called flow-capacity index (FCI), the ratio of kh well (well test-derived value) to kh matrix (core-derived property). Data from 80 wells showed kh matrix to be consistently higher than kh well, a relationship that suggests insignificant fracture production in these wells.
The Wafra field is in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, as shown in Fig. 1. The field has been producing since the 1950s and has seen renewed drilling activity since the late 1990s, including horizontal drilling and implementation of peripheral water injection (Davis and Habib 1999).
The Lower Cretaceous Ratawi formation contains the most reserves of the producing intervals at Wafra. The Ratawi oolite (a misnomer--it is a grainstone) reservoir has variable porosity (5 to 35%) and permeability that ranges from tens to hundreds of md (Longacre and Ginger 1988). The main Wafra structure is a gentle (i.e., interlimb angle >170°), doubly plunging anticline trending north-northwest to south-southeast, which culminates near its northern end. The East Wafra spur is a north-trending branch that extends from the center of the main Wafra structure. As seen in Fig. 1, relief on the Main Wafra structure exceeds that on East Wafra.
The Ratawi oolite in the Wafra field has been studied at length, and various authors have reported geologic and engineering elements, leading to reservoir characterization and understanding of reservoir performance. Geologic studies are those of Waite et al. (2000) and Sibley et al. (1997). In contrast, Davis and Habib (1999) presented implementation of peripheral water injection, whereas Chawathé et al. (2006) discussed realignment of injection pattern owing to lack of pressure support in the reservoir interior.
Previous studies considered the reservoir to behave like a single-porosity system. But recent image-log fracture interpretations indicate high fracture densities, suggesting that the implementation of a dual-porosity model may be necessary because the high impact of fractures during field development has been recognized in some Middle East reservoirs for more than 50 years (Daniel 1954). Static and dynamic data are required to characterize fracture reservoir behavior accurately (Narr et al. 2006). Geologic description of the fracture system, by use of cores, borehole images, seismic data, and well logs, does not in itself determine whether fractures affect reservoir behavior. While seismic and some image logs were available to locate fractures in the Wafra Ratawi reservoir, no dynamic testing with the specific objective of understanding fracture impact has occurred. So, to determine whether fractures influence oil productivity significantly, we used diagnostic analyses of production data and well tests of available injectors. The assessment of fracture effects in the Ratawi reservoir will be used to guide the next generation of geologic and flow-simulation models.
Dynamic data involving pressure and rate have the potential to reveal the influence of open fractures in production performance. Unfortunately, pressure-transient testing on single wells does not always provide conclusive evidence about the presence of fractures with the characteristic dual-porosity dip on the pressure-derivative signature (Bourdet et al. 1989). That is because a correct mixture of matrix/fracture storativity must be present for the characteristic signature to appear (Serra et al. 1983). In practice, interference testing (Beliveau 1989) between wells appears to provide more-definitive clues about interwell connectivity, leading to inference about fractures.
In contrast to pressure-transient testing, rate-transient analysis offers the potential to provide the same information without dedicated testing. In this field, all wells are currently on submersible pumps. Consequently, the pump-intake pressure and measured rate provided the necessary data for pressure/rate convolution or rate-transient analysis.
We provide the Ratawi-reservoir case study primarily as an example of the integration of diverse geologic and engineering data to develop an assessment of fracture influence on reservoir behavior. It illustrates the use of production-data diagnostic tests to determine fracture influence in the absence of targeted fracture-analysis testing. The workflow can be applied to similar static/dynamic problems, such as fault-transmissivity determination. Secondly, this analysis illustrates the process of deciding that fractures, although present throughout the reservoir, may not lead to widespread fractured-reservoir characteristics (e.g., Allan and Sun 2003).
The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined a Lower Cretaceous grainstone for which production extending over 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity and overall effect have been elusive. This study attempts to discern open fractures, if any, and their locations to facilitate building next generation earth and flow-simulation models.
The geological assessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, attesting to the notion of localized fracture response. The spatially-restricted fracture signature may be owing to fracture or vug zones, or to low-permeability reservoir.
Presence of fractures was discerned by constructing the so-called flow-capacity index (FCI), which is the ratio of khwell (welltest-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, with the p-50 reciprocal-FCI being 13, a relationship that suggests insignificant fracture production in these wells.
The Wafra Field is located in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, as shown in Fig. 1. The field has been producing since the 1950's and renewed drilling activity since the late 1990's includes horizontal drilling and implementing peripheral water injection (Davis and Habib 1999).
The Lower Cretaceous Ratawi Formation contains the most reserves of the producing intervals at Wafra and its Ratawi Oolite (a misnomer; it is a grainstone) reservoir has high porosity and permeability (Waite et al. 2000). The main Wafra structure is a gentle (i.e., interlimb angle >170°), doubly-plunging anticline trending NNW-SSE whose culmination is near its northern end. The East Wafra spur is a north-trending fork off the center of the main Wafra structure. As seen in Fig. 1, relief on the Main Wafra structure exceeds that on East Wafra.