The two most popular fracture placement methods in unconventional shale with multiple stages fracturing completion are wireline plug-n-perf and pinpoint perforating / fracturing using coiled tubing. The debate regarding which method is better is still unresolved, as each method has its performance and economic advantages, which make the selection decision very challenging for practitioners and decision makers. In the Antelope Shale reservoir in Monterey Formation, each of these two fracture placement methods were implemented for multi-stage fracturing in 4 vertical offset wells to evaluate the benefits and associated risks, and to identify the preferred method for a full field development plan. The plug-n-perf method had multiple clusters perforated with wireline for each frac stage, whereas the coil tubing method utilized sand-jets to create pinpoint perforation holes with single cluster. In this paper, we discuss the lessons learned and results from application of both fracture placement methods in Antelope Shale using key performance and economic indicators, including time efficiency, cost, production, fracture geometry and zonal coverage. The multitude of operational events experienced during these completion executions demonstrated both the associated benefits related to improved efficiency (efficient completion execution without trouble, record number of completions in single day, etc.) and disadvantages in terms of delayed operation (perforation guns not firing, CT parting, multiple fishing operations during drill out of plugs, ineffective perforation cutting, depth control of CT, etc). The results from various diagnostics such as microseismic, tiltmeters, Diagnostic Fracture Injection Test (DFIT), tracers, etc. were used to compare the effective pay zone coverage with multiple fracture stages, fracture geometry and well productivity for both fracture placement methods. For multi-stage fracturing completions in tight rock, an understanding of risks, rewards, and economic impact of both methods is crucial to completion and stimulation strategy.

In new shale development, formation testing is critical to understanding reservoir properties and producibility. However, due to low permeability, a test usually takes much longer and can easily result in cost overruns. There are many ways to conduct formation testing such as drill pipe / tubing conveyed testing and coil-tubing or wireline testing. Formation wireline testing has advantage not only for its flexibility and combinable features but also for cost and time savings as compared to other methods. In a combination way, formation wireline tool can be run either through wireline alone or through the drill pipe for safety reasons. The Antelope Shale in Monterey Formation in San Joaquin Valley is siliceous shale that is thinly laminated, has relatively high porosity, low permeability, small pore throats, and varying degree of fracturing. Siliceous shale hydrocarbon reservoirs are not very common and little is known about their production characteristics. These are much more geologically complex than the conventional shale and tight rock reservoirs and the traditional conventional formation testing methods may not be directly applied to them. Little or no literature review can be found on running formation evaluation wireline tools in the Antelope Shale. In this paper, we discuss a case study of formation testing in Antelope Shale. The test was run with dual packers and downhole fluid analyzer in a vertical appraisal well to evaluate two intervals in the Antelope Shale. The run proved the value of formation testing method in terms of data collected versus cost & time. First, the drill pipe conveyed formation testing was selected among different methods to help characterize the reservoir and to measure fracture closure pressure to evaluate technologies that can lead to the development of tight reservoirs. Second, the microfracturing data collected from the formation testing job was used for designing the completion strategy to understand individual zone production such that we may target a single zone for future development. The additional values of the formation test were to measure formation pressure and collect fluid samples for Pressure, Volume, and Temperature (PVT) analysis to minimize uncertainties in key reservoir parameters. The job proved its pivot values for formation testing. However, the experience from planning and running the tool in this new tight rock reservoir are much more important to achieving the appraisal objectives. The combinable features of the tool enabled continuous onsite monitoring, on-the-fly operational decision making in sample depths in response to formation behavior, and optimizing sample chamber opening time to collect critical oil and water samples, while successfully acquiring the fracture closure pressure. These results may be difficult to achieve with other methods in a single run.

In shale development, picking optimum lateral landing points, and accurately predicting the height to which a hydraulic fracture will grow, requires knowledge of the vertical stress profile for both the target reservoir and the bounding layers. Stress profiles can be estimated using modern sonic logs in conjunction with geomechanical models but they require calibration with direct measurement of stresses from diagnostic testing, such as micro-fracture testing. The organic-rich middle Miocene to lower Pliocene Monterey Formation is the main producing reservoir rock in the Southern California Offshore area. The most desirable reservoir rocks are the lower calcareous and massive chert zones due to the abundant presence of natural fractures which are necessary for these zones to be economically productive. The Antelope shale, the Monterey equivalent in the San Joaquin valley, may hold the same production potential. However, due to low permeability and less natural fracture density, the economic development of the Antelope shale will require stimulated completions. This paper discusses the first case study on microfracture testing in the Antelope Shale. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical resolution nearly corresponds to log scale. Therefore, microfracture testing is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. Further, these calibrated models helped to identify potential fracture boundaries across wellbore and evaluate fracture growth using 3D frac simulator. This resulted in optimized perforation and frac placement in multi-stage frac completion. Microfracture tests were compared with leak off tests across adjacent wells to give more confidence in mud weight window for safe drilling. The closure stress calculated from calibrated sonic logs served as a yardstick for comparing with Leak off Test (LOT) and Formation Integrity Test (FIT) data. The closure stress along with corresponding formation pressure was used to adjust upper and lower boundaries of mud weight window for safe drilling. The case study demonstrates the effective integration of microfracture testing with sonic logs in the Antelope shale.

Understanding zonal contribution is imperative in a well with comingled production from multiple stimulated zones. This has even more importance in shale plays where a primary appraisal objective is to identify the prolific zones with a vertical well to decide which layers of the formation will be targeted for future development. The use of measured inflow over time of each targeted zone provides an excellent methodology to establish zonal contribution and wellbore evaluation. The Monterey Formation in the southern San Joaquin valley of California produces from three silica phases. While the industry has been pretty successful in producing from the shallow Diatomite rock via cyclic steam operations, the deeper silica-based resources available in the Antelope Shale have yet to be commercially established. Extracting hydrocarbons locked in these silica phases requires unconventional technologies to access the high porosity / low permeability network. Unconventional completions require greater front-end cost and carry an increased risk to return on investment. To minimize the risk, each pay zone needs to be effectively described using both theoretical and empirical data. In this paper, we present and discuss a case study where chemical-based tracer technology was used to develop an accurate identification of the distinct pay zones within the different silica phases of the Antelope Shale. Unique oil-phase chemical tracers were applied during the permitted hydraulic fracturing on four vertical wellbores that gave an insight into the zonal production contribution and helped narrow potential zones for future development. In comparison to tool based zonal contribution measurement methods, which provide a snapshot in time measurement, the chemical tracers provided the capability to monitor and measure inflow over a longer period indicating that zonal contribution varied with time. Some formation layers produced immediately and then declined, while others took longer to cleanup and start contributing to total production. These results helped narrow the uncertainty around the potential target zones.

Data Science is the current gold rush. While many industries have benefitted from applications of data science, including machine learning and Artificial Intelligence (AI), the applications in upstream oil and gas are still somewhat limited. Some examples of applications of AI include seismic interpretations, facility optimization, and data driven modeling – forecasting. While still naïve, we will explore cases where data science can be used in the day to day field optimization and development. The Midway Sunset (MWSS) field in San Joaquin Valley, California has over 100 years of history. The field was discovered in 19011 and had limited development through the 1960s. Since the start of thermal stimulation in 1964, the field has seen phased thermal flooding and cyclic stimulation. Recently there has been an increase in heat mining vertical and horizontal wells to tap the remaining hot oil. As with any brownfield, the sweet spots are long gone. Effort is now to optimize the field development and tap by-passed oil, thereby increasing recovery. The current operational focus includes field wide holistic review of remaining resource potential. Resources in the MWSS reservoirs are produced by cyclic steam method. Cyclic thermal stimulation has been effective as an overall depletion process and for stimulating the near wellbore region to increase production. It is imperative to properly identify target wells and sands for cyclic stimulation. Cyclic steaming in depleted zones or cold reservoirs is often uneconomical. The benefit comes when we can identify and stimulate only the warm oil. Identification of warm oil and short listing the wells for cyclic stimulation is a labor-intensive process. The volume of data can get so large that it may not be feasible for a professional to effectively do the analysis. In this paper, we present a case study of data analytics for high grading wells for cyclic stimulation. This method utilizes the machine power to integrate reservoir, and production data to identify and rank wells for cyclic stimulation and potentially increase success rate by minimizing suboptimal cyclic candidates.