Integrated Hydraulic Fracturing and Well-Test Data Analytics using R

Permeability of the cleat system is a key factor controlling the productivity of CSG reservoirs and, therefore, the commerciality of development projects. Well testing is routinely used to provide representative values of coal permeability. The authors’ experience has shown pressure transient behaviour in coal reservoirs to be similar to those in primary porosity systems, with pseudo radial flow frequently observed, and the dual-porosity signature largely absent. Despite the authors’ best efforts in test design, large permeability variation and extremely high skin factors have been seen. The authors have run variations of drill stem tests (DSTs), injection tests, and wireline tests to understand the dependency of results to test methods, and the validity of results obtained. Pertinent examples of each type of test are discussed. Finally, recommendations to reconcile well test results to actual well performance are presented.

In current economic and environmental contexts, the optimization of long, horizontal well completion and the maximization of individual well performance are becoming increasingly important. The challenge is to be able to start improving the production efficiency while designing an adapted completion for each well without compromising the project economy. The cost-effective formation evaluation technique described in this paper allows rapid identification of dynamic heterogeneities along the reservoir after the drilling of a horizontal well. This key information then can be used to optimize well completion and treatment. This new approach, called WTLog, combines well testing and logging techniques and was introduced initially for the optimization of unconventional well completion (Jacques et al., 2019 and Manivannan et al. 2019). The log begins by circulating a low-viscosity liquid that can be injected in the formation through the mud cake. The brine circulation operation is run at the end of the drilling phase, after reaching TD of the drain while maintaining a constant wellhead pressure at the wellhead. The constant pressure control can be applied without a specific additional choke device when Managed Pressure Drilling (MPD) is used to drill the formation section. The inlet and outlet flowrates are measured accurately, and their difference corresponds to the apparent formation-injection rate. The depth of the interface between the two liquids inside the borehole is estimated from the flowrates and pressure measured at the wellhead. Combining these data allows derivation of the low-viscosity/liquid-injection profile along the open hole. A permeability log then can be derived by inversion. Well Test Logging has been applied successfully for the first time on two horizontal wells in a conventional carbonate reservoir. The interpretation results were benchmarked to static conventional openhole logs and validated against the data log obtained by the dynamic production log tool (PLT) performed after well start-up. This technique opens new perspectives for optimizing well completion in these carbonate-fractured formations for which porosity logs might not be a good permeability indicator and where conductive fractures seen on image logs are not always indicative of future production.

Abstract The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021. A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types. This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.

In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.