No abstract

Sooner Trend Anadarko Canadian Kingfisher, also known as STACK, is a booming unconventional oil play in North America. As one of the main features that makes the asset profitable, multiple targeting benches raise a challenge of optimization. Well-developed natural fracture system brings in another level of complexity to estimate well spacing. This study introduces an integrated workflow to better understand the fluid flow mechanism in the reservoir and optimize development strategy. From borehole image log, natural fracture orientation and density was interpreted and statistically populated into geologic model along with petrophysical properties. To account for productivity enhancement due to natural fractures, enhanced permeability was embedded into the simulation model according to the distribution of discrete fracture network. After being history matched, the reservoir model was used to test the sensitivity on well spacing, landing zone and hydraulic fracturing pump schedule. Both infill drilling program and green field development scenarios were tested and compared to optimize our field development study. Production history match indicates that natural fractures serve as fluid flow conduit and contribute significantly to the production in Osage. Pressure transient observation shows a similar reservoir behavior in the Osage as opposed to the Woodford. Multiple wells experience productivity reduction over longer production history, indicating near-field damage (such as scaling) and/or far-field damage (such as fracture closure). Introduction of skin factor and pressure dependent permeability captured the trend on productivity behavior in the history match. In addition, the simulation study shed light on the hydraulic fracture geometry that provides direct insight on well spacing and landing zone analyses. Results from the infill drilling program show that staggered design with 3 Osage and 4 Woodford wells per section yields the higher oil recovery. However, using the greenfield sensitivities, and depending on the pumping schedule, hydraulic fractures from Woodford wells show upward growth, draining both formations effectively even without Osage wells. This study provides valuable information about the development strategy in STACK unconventional resources, particularly for scenarios with natural fracture system and multiple targeting zones. The simulation workflow considers well interference in both horizontal and vertical directions simultaneously to optimize oil recovery and reduce operational cost.

We analyzed a synthetic transfer zone and its associated fault planes and relay ramp in Penobscot, a potential offshore field in the Scotian Basin. Transfer zones are structural areas where one fault dies out and another fault begins, forming a relay ramp in the middle. They can be categorized as divergent, convergent, and synthetic transfer zones depending on the relative location and dipping directions of the faults. These zones not only play an important role in fluid migration but also help interpreters delineate secondary features such as fractures, splay shears, and Riedel faults. Commonly those faults would branch into smaller splays and the relay ramp can get “breached” with connecting faults with the increase of slip. The study area in the Scotian basin is characterized by two major listric normal faults dipping in the same direction giving rise to a synthetic transfer zone. These faults are clearly visible on seismic attributes, including curvature and coherence slices extracted along the top of the Cretaceous Petrel Formation. However, when analyzing the seismic attributes along the overlying Wyandot Formation’s top, we observe channel-like features, which run parallel as well as at an angle to these faults. However, when we performed further analysis using seismic amplitude’s vertical slices, interpreted horizons, and seismic attributes, we found that these features are not channels. We divided the features into two types, the first is parallel to the main faults and can be associated with the grabens formed by synthetic and antithetic secondary faults (NE-SW). The second type is related to the polygonal faulting associated with differential compaction and gravitational loading of the Wyandot Chalk Formation. Apart from the two lineations, there are NNE-SSW oriented lineations which are an impression of basement faulting, and NNW-SSE oriented lineations representing acquisition footprint.

Synthetic transfer zones develop between fault segments which dip in the same direction, with relay ramps connecting the fault blocks separated by the different fault segments. The characteristics of the transfer zones are controlled by the lithology, deformation conditions, and strain magnitude. The Parihaka fault is a NE-SW trending set of three major en-echelon faults connected by relay ramps in the Taranaki Basin, New Zealand. The structure in the basin is defined by extension during two episodes of deformation between the late Cretaceous and Paleocene and between the Late Miocene and recent. To better understand the evolution of a synthetic transfer zone, we study the geometry and secondary faulting between the individual fault segments in the Parihaka fault system using structural interpretation of 3D seismic data and seismic attributes. This interpretation allows for a unique application of seismic attributes to better study transfer zones. Seismic attributes, including coherence, dip, and curvature are effective tools to understand the detailed geometry and variation in displacement on the individual faults, the nature of secondary faulting along the transfer zones, and the relationship between the faults and drape folds. Seismic characterization of the fault system of Miocene to Pliocene age horizons highlights variations in the degree of faulting, deformation, and growth mechanism associated with different stages of transfer zone development. Coherence, dip, and curvature attributes show a direct correlation with structural parameters such as deformation, folding, and breaching of relay ramps.. All three attributes enhance the visualization of the major and associated secondary faults and better constrain their tectonic history. The observed correlation between seismic attributes and structural characteristics of transfer zones can significantly improve structural interpretation and exploration workflow.

The San Andres is a well-known dolomitic enhanced oil recovery target with low matrix permeability in the area of interest (Yoakum County, TX). A reservoir simulation study was undertaken to investigate the feasibility of using horizontal multi-fractured wells in low permeability miscible floods. A reservoir model was developed for the area of interest and was history-matched with the primary production data from the field. The model was then used to illustrate the CO2 miscible flood potential by quantifying the incremental recovery over the primary production scenario. Compositional modeling was used in the study to evaluate CO2 flooding feasibility and efficiency. A holistic workflow including PVT modeling, petrophysical analysis, geomodeling, and hydraulic fracture modeling, provided integrated input into the reservoir model. Continuous CO2 flooding was explored as an operating strategy. Furthermore, water alternating gas (WAG) cases were designed and run as a more realistic and cost-effective method of implementing miscible flooding. Based on the history-matched model, sensitivity analyses were conducted on hydraulic fracture geometry, well spacing, injection patterns and operating conditions for the primary production scenario, continuous CO2 flooding and WAG scenarios. Field surveillance and observations during the history-matching process showed that the wells had undergone damage from scaling. Sensitivity analysis showed that 300ft to 400ft cluster spacing resulted in the highest oil production during the first 10 years. Interdependent parameters such as well spacing and fracture half-length were studied together; this sensitivity review showed that the differential oil recovery from 128 acres to 160 acres was larger than that from 160 acres to 213 acres, leading to the recommendation that 160 acres could be the optimized well spacing. In the optimized design, the continuous CO2 injection case showed an incremental oil recovery of 22% (compared to primary production). The CO2 utilization factor was between 7 and 8, which was consistent with the reported value from literature. WAG sensitivity analysis showed that longer hydraulic fractures did not necessarily improve WAG efficiency, but led to earlier CO2 breakthrough. This observation confirmed our early suspicion that smaller hydraulic fracturing treatment could be a more cost-effective design for miscible flooding in this reservoir. In addition, sweep efficiency and recovery were sensitive to WAG ratio, but not to injection slug size in each cycle.