Integrated Work Flow Optimizes Eagle Ford Field Development
The complete paper presents a large-scale work flow designed to take a vast amount of data into consideration. The work flow can be scaled for projects of any size, depending on the data available.
An integrated project can take many forms, depending on available data, from a simple horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations to a large-scale seismic-to-simulation work flow. The complete paper presents a large-scale work flow designed to take a vast amount of data into consideration. The work flow can be scaled for projects of any size, depending on the data available.
In 2017, Chesapeake Energy launched an investigation to evaluate ways of improving overall recoveries within the lower Eagle Ford. Two theoretical approaches were generated to optimize the company’s development plan: modification to current completion designs to achieve greater near-well fracture complexity and modification of targeting strategies to more-effectively drain the Eagle Ford interval.
To evaluate these approaches, the company acquired multiple data sets to provide an integrated study. An already developing and productive area was selected in southwest Texas to examine completion design and targeting strategies while attaining a data set to allow for complex completion monitoring and reservoir simulations to aid in subsequent development optimization while maintaining at least type-curve production.
Microseismic was acquired on three wells with multiple downhole arrays used to visualize how fracture geometries were affected by completion design changes. For quality control, data from ultrasonic image tools, cement-bond logs, and gyros were acquired to increase confidence in microseismic results. Time-lapse 2D lines were acquired pre- and post-hydraulic fracture to measure seismic changes induced by completions. Water- and oil-soluble tracers were run to determine hydraulic fracture extent and drainage footprint. Parent wells were instrumented with surface pressure gauges to characterize hydraulic fracture hits. With permanently installed fiber, a post-hydraulic fracture downhole camera was run to examine cluster efficiency per completion design. Core and quad-combo logs were taken in the area to analyze compositional similarities in oil signatures compared with produced oil and to calibrate petrophysical and geomechanical values. Oil samples were collected and analyzed to derive an equation of state for fluid characterization and reservoir simulation. Natural fracture characterization was performed to determine the pre-existing geological fabric of the rock using lateral electrical borehole images, a field outcrop study, and quad-combo and fracture-identification logs derived from drilling data. Multiple facture calibration tests were collected in the study area at different target intervals to calibrate vertical stress profiles and examine reservoir pressures. Lastly, following 1 year of production, a temporary rod-conveyed fiber-optic production log was run to determine cluster contribution based on completion design. The independent data sets were integrated on a common commercial software platform for geomodel creation, discrete natural fracture characterizations, hydraulic fracture simulations, and reservoir simulations. An integration strategy was developed to bring together the vast amount of data acquired. The work flow is a simplified representation of the data interdependencies and was used throughout the study. Only five data acquisitions are shown to overlap; however, any change in interpretation can lead to revision and iteration of several interdependent segments.
Although acquisition of this complex data set encountered a series of obstacles that were overcome, the project team successfully integrated, analyzed, and interpreted the results to generate adjustments to the current development program. The complete paper details the work flows generated and modified, along with lessons learned in the acquisition of this robust data set through the generation and integration of the results.
The classic Eagle Ford depositional sequence in the subsurface consists of a retrogradation lower member and a progradational upper member. These two members separate at or near the maximum flooding surface. In the study area, most of the upper member of the Eagle Ford is truncated beneath the unconformity at the top of the Eagle Ford.
One vertical cored section is located within the study area. The major reservoir within the cored interval occurs in marlstones, while potential internal baffles and barriers are tight limestones (1–2% porosity) and thin, clay-rich bentonites. These lithologies were added to the core well downhole log after the core-to-log shift was ascertained, and the correlation of reservoir and potential baffles was determined using the core as a template. Log correlations across a 57‑well section were analyzed to show the continuity of these geological features across the study, using a calcite-rich continuity throughout the study area.
The core measurements were then used to calibrate the petrophysical and geomechanical model. Four electrofacies models on the core well (limestone, organic rich marlstone, organic poor marlstone, and high clay content) were created using a combination of normalized gamma ray, deep-resistivity, and compressional sonic logs.
In this study, the team’s robust work flow took into account field data acquisition (seismic, 4D seismic, and chemical tracers), laboratory [geomechanical, geochemistry, and pressure/volume/temperature (PVT)] measurements and correlations, petrophysical measurements (characterization, facies, and electrical borehole images), and real-time field-surveillance (microseismic and fracture-hit prevention and mitigation programs through pressure monitoring) and integrated all the components of a complex large-scale project into a common simulation platform (seismic, geomodeling, hydraulic fracturing, and reservoir simulation) that was used to run sensitivities.
Independently, the various data sources and interpretations are valuable for gaining immediate insight. However, when the information is taken as a compiled data set of independent measurements, a multidisciplinary team is ideal for extracting in-depth value to identify primary reservoir drivers.
Data Used for Simulation
- All completion designs contributed to the fracture-driven pressure response in the two legacy monitor wells. The pressure response of the monitor wells for each completion design was variable and demonstrates that no design removes completely the risk of hydraulic fracture hits.
- Simulated hydraulic fracture geometries coupled with fracture-driven pressure responses indicate that each hydraulic fracture design creates a different fracture geometry, and the low fracture-driven pressure response of crosslinked designs indicates a higher likelihood of generating near-wellbore complexity necessary for increased recovery efficiencies with the added benefit of reducing fracture-hit intensities. Simulation showed that hybrid and slickwater designs created larger half-lengths and increased the fracture-driven pressure communication on the legacy wells. In addition, when changing the completion design to contain more and closer clusters or variable rates, even higher fracture-driven pressure responses were observed.
- This study found no correlation between natural fracture intensity and hydraulic fracture interference on legacy wells.
- Buildup of a pressure barrier between the parent and the child well and zipper hydraulic fracture interior wells saw greater microseismic complexity, which may indicate higher near-wellbore complexity. The leading child well hydraulic fracture hits show that a crosslinked design provides the least fracture-hit effect over a slickwater design and shortest half-length from microseismic acquisition.
- Time-lapse oil sampling and reservoir modeling indicates that staggered landing effectively drains the lower Eagle Ford vertically and horizontally. Initial oil signatures show high compositional similarities among the oil samples from different target zones. After more than 270 days, oil composition showed vertical compartmentalization, with oil compositions reflecting the zone at which the wellbore was targeted.
- When comparing more than 100 simulations, the hybrid job design generated consistently larger fracture half-lengths and comparable fractured surface area with lower fluid per foot.
- A 4D seismic experiment was not elaborated upon in the complete paper because results from the pre- and post-hydraulic fracture imaging did not show any meaningful response. It is speculated that the strong impedance contrast between the Buda and Eagle Ford masked any discernible response.
- This case study makes use of seismically derived properties, acquired and simulated microseismic data, hydraulic fracture simulations, borehole image logs, and geological observations from outcrops. These data were used to create a discrete fracture network (DFN) presented in the case study. However, this is one realization of the DFN, observationally defined as a decent match based on trend and aerial overlap. Ideally, a second borehole image log would be used to calibrate natural fracture intensity distribution.
- A hybrid completion design is recommended for the infill wells not directly adjacent to legacy wells.
- Wells immediately adjacent to legacy wells are led three to five stages ahead of remaining infill wells on the pad. Then, the remaining wells are zippered so that the interior wells are completed last. This will build pressure across the pad, allowing the interior infill wells to have greater microseismic concentration.
- Microseismic lateral extent consistently exceeded well spacing by three times. This observation, together with analysis of hydraulic fracture simulations, water tracers, and oil samples, indicates that wells are efficiently connected, increasing the overall pad stimulated rock volume.
- Time-lapse oil samples showed compositional separation in oil signatures for the lower Eagle Ford over time, suggesting that wine-rack development is effective in draining the interval.
- Implementation of field-development strategies resulted in a 12% increase in oil production for the wedge program during 2017 and a more-sustained, flatter base-production profile in 2018.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195951, “Case Study: Optimizing Eagle Ford Field Development Through a Fully Integrated Work Flow,” by Adrian Morales, SPE, Robert Holman, and Drew Nugent, Chesapeake Energy, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September–2 October. The paper has not been peer reviewed.