Designing hydraulic-fracture stimulation to optimize well productivity requires a carrier fluid with a suitable leakoff coefficient and knowledge of the initial reservoir pressure and permeability, the closure-stress magnitudes in the reservoir and in the bounding formations, and rock properties such as the Young's modulus and the Poisson's ratio, which can be determined from cores. When key parameters are left unknown, the hydraulic-fracture stimulation is likely to be severely suboptimal.
This study integrates pressure-buildup and production transient analyses with microseismic surveys and the recorded pumping schedule to estimate the aforementioned parameters in previously fractured wells in a tight gas reservoir that have been on production for up to 8.5 years.
The first well drilled and completed in the block included a pressure-buildup test that enabled accurate estimation of the initial reservoir pressure and permeability. A post-fracture buildup test was also conducted, and annual pressure-buildup tests in the subsequent 6 years showed continuous changes in the fracture morphology, with fracture conductivity decreasing by a factor of three and fracture length increasing by approximately 50%. Many of the subsequent wells were drilled in two patterned well clusters, each designed to account for fracture-propagation behavior indicated from a microseismic survey. A comparison with an optimal hydraulic-fracture design that was intended to maximize well productivity indicates that most of the well stimulations were suboptimal, with rate and cumulative production approximately one-half of an optimized design on the basis of the same proppant mass.
The observed changes in fracture conductivity and length over time were not anticipated. Because such data are rarely recorded, the variations in fracture morphology may be fairly typical and should be of considerable interest to pressure-transient analysts. The production-data analysis shows the difficulties in determining formation and fracture parameters when the transient response lacks radial flow. The fracture-treatment analysis shows a comparison between the actual fracture treatment and one designed to maximize well productivity, and clearly illustrates the potential for well improvement through the use of modern hydraulic-fracture-design principles.
Pang, Wei (Sinopec Research Institute of Petroleum Engineering) | Ehlig-Economides, Christine A (University of Houston) | Du, Juan (Sinopec Research Institute of Petroleum Engineering) | He, Ying (Sinopec Research Institute of Petroleum Engineering) | Zhang, Tongyi (Sinopec Research Institute of Petroleum Engineering)
The stimulated reservoir volume (SRV) estimated from daily production rate and pressure is a vital parameter for appraising shale gas wells’ fracturing effect and production potential. However, when well interference occurs, the SRV estimation from rate-normalized pressure (RNP) analysis is compromised. This paper illustrates diagnosis of well interference and how it affects SRV calculation.
China is the third country to exploit the shale gas technology breakthrough after the United States and Canada. The Jiaoshiba shale gas play is the most successful shale gas reservoir in China with some wells’ cumulative production over 0.1 billion cubic meters in the first year. Production rate data has shown jumps in water production during hydraulic fracturing of neighboring wells. By combination of hydraulic fracturing process and production data, we detect the existence of well interference from the adjacent well, when well interference happens and the influence it imposed on the target well. We analyzed two pairs of target and neighboring shale gas well pairs using the RNP and its derivative. The log-log diagnostic plots for nearly all of the wells see unit slope, indicating boundary dominated flow within 1 year. Some wells see two unit slopes possibly indicating a change in the SRV after hydraulic fracturing in a neighboring well.
Well interference may be caused by interaction between primary hydraulic fractures and/or secondary natural fractures activated during hydraulic fracturing. Interwell interference has had a significant influence on the SRV interpretation.
Well interference has drawn people's attention in recent years, but its impact on SRV interpretation is rarely reported. This research may help to characterize shale gas's SRV and related parameters and to optimize well spacing.
This paper describes an innovative approach to integrate pressure transients with numerical reservoir simulation models. The derivative plot, from analytical Pressure Transient Analysis, is used to aid history match pressure transients measurements directly into the production history matched numerical reservoir simulation model. Most often only the extrapolated pressure is explicitly (as a single point measure) incorporated for history matching the reservoir material balance. Characterization of heterogeneity and complex reservoir features such as barriers, and aquifers are subjectively incorporated or inferred in the simulation model from analytical solutions. Furthermore analytical techniques cannot account for all geometrical descriptions and are limited at describing multiphase flow and well interference.
This methodology expands on traditional reservoir simulation history matching by incorporating a stepwise approach in matching geological features on an already built conventional reservoir simulation model. An actual field example is discussed to illustrate on how this methodology populates properties away from the wellbore in terms of grid blocks based on the pressure diffusion regimes of the derivative plot rather than using averaged terms such as the analytical radius of investigation or matching it in a Cartesian plot. It consists of adjusting the simulation model sequentially: wellbore storage, near wellbore permeability (kh and skin), permeability away from the wellbore and boundaries to match the complete spectrum of the observed pressure derivative. Additional field examples illustrate the benefits of this methodology in the context of a multi-well development scenario: The presence of a gas injector that was initially interpreted as a closed boundary and the expected interference response between multiple producing wells.
With this approach an improved description and reduced uncertainty is obtained for the reservoir simulation model, providing a more accurate production forecast to estimate reserves, optimize the reservoir management plan and/or to evaluate additional development scenarios.
Oil production from the Bakken formation has been active for 60 years and has applied three well completion design strategies in three different eras: mainly hydraulically fractured vertical wells before 1987, horizontal wells before 1991, and mainly multiple transverse fracture horizontal wells since 2006. Reported production data enables comparisons of well performance during these eras.
This study employs the log-log graph of rate (q) versus material balance time (Q/q) to diagnose transient (slope -¼ or -½) and boundary dominated flow (BDF) (slope -1) behavior. Wells from the 3 eras show mainly 3 types of flow regime sequences seen as straight trends on the log-log graph of rate versus material balance time: -¼ to -1, -½ to -1 and -¼ to -½ to -1. Flow geometries corresponding to various flow regime sequences are related to specific well and formation characteristics. Then we extrapolate the BDF behavior to estimate the EUR for each well when possible.
We observed that both the average well EUR and the average well rate at start of BDF behavior is highest for the multiple transverse fracture horizontal well completion design. This project also investigates the behavior of the GOR versus material balance time (MBT). Three types of GOR behavior were observed: constant, constant followed by sharp increase, or scattered. In all three eras, the EUR was highest in wells with constant GOR behavior followed by sharp increase. The sharp increase likely signals flow below the bubble point pressure. The lower EUR in wells that did not produce below the bubble point pressure shows that solution gas drive behavior enhances the EUR. Lower EUR in wells with scattered GOR behavior may be attributed to unstable well production.
This study shows how to use long term production behavior to gain important insights about well designs and why some wells have higher EUR and rate behavior.