|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.
Bethancourt, Roswall (ADNOC ONSHORE) | Aguilar, Victor (ADNOC ONSHORE) | Mubarak Al Braiki, Ali (ADNOC ONSHORE) | Dua, Ajay (ADNOC ONSHORE) | Sarhan, Mohammed (ADNOC ONSHORE) | Al Blooshi, Nouf (ADNOC ONSHORE) | El Wazeer, Fathy (AlMansoori Specialized Engineering) | Khalife, Bassam (AlMansoori Specialized Engineering) | Propper, Maarten (Cordax Evaluation Technologies Inc.)
As mature reservoirs continue to be produced, drilling activities become more and more challenging. Risks are mainly posed by large variations in pressure gradient, while having intercalated high- and low-pressure zones adds to the complexity of the operation. High mud weigh is often used for well control and hole stability; however, it may result in lost circulation, differential sticking or wellbore collapse. On the other hand, increasing depletion may further cause compaction, and therefore instability. Wellbore trajectory and deviation may be extra factors increasing the hazard likelihood. In such circumstances, stuck pipe, which is one of the main drilling problems worldwide, seems like an imminent risk that generally is addressed on a reactive basis, amounting to 25% - 40% of the well budget, according to industry literature. Furthermore, the presence of radioactive sources, necessary for measuring and recording density / neutron petrophysical data, in the LWD (Logging While Drilling) string while drilling across such reservoirs augments the severity of the potential risks. This paper aims to present the significant gains obtained by incorporating the Logging While Tripping (LWT) technology in the standard operational practices, while meeting the drilling, formation evaluation and data acquisition requirements.
Data from three sample wells were analyzed: In Well A, the 8.5" section was drilled in two runs: - Run-1 - RSS (Rotary Steerable System) + Triple Combo LWD above the high overbalance zone X. Run-2 - RSS only till section TD (Total Depth). In Well B, the 8.5" section drilling was attempted in a single run, leading to stuck BHA (Bottom Hole Assembly) with expensive LWD tools and radioactive source, and eventually leaving the total BHA in the hole and sidetracking the well. In Well C, the 8.5" section drilling was again attempted in a single run, but only with GR-RSS for landing inside the reservoir. Formation evaluation data was acquired using LWT technique, which requires negligible additional rig time, and virtually eliminates the risk of losing expensive LWD tools and radioactive sources in the well, as the logging tools are protected inside the pipe and retrievable at any time.
Rig time, cost and risk were evaluated and compared for the three cases. Results show 1.85 days rig time reduction and 23% cost savings in Well C compared to Well A, while statistics of Well B showcase the risk magnitude, which can be effectively diminished by implementing the methodology used in Well C. A quantified matrix has been utilized to contrast the approximative cumulative risk per well. The use of LWT in 8.5" deviated hole sections has become part of the best operational standard practices for the operator while drilling across depleted and deeper reservoirs, as it leads to optimal time - cost - risk balance.