With a US $1 million/d average spread rate, deepwater operations demand that risk and uncertainty be properly quantified. Operators would probably agree that optimal use of integrated software mitigates risk; however, they may disagree as to when software can have the most impact on the deepwater process.

Validating deepwater prospects in an integrated E&P software platform is essential for success. Petroleum systems modeling software is used to evaluate basin history and understand its chronostratigraphic and structural development – the thermal maturation of the source rock, expulsion of hydrocarbons over time, and eventual entrapment.

Prospect assessment is undertaken to model geologic complexity, quantify risk, and examine the full range of possible risked-prospect volumes. Using exploration economics software to simulate exploratory drilling, appraisal, and development activities delivers the range of expected after-tax economic value. This enables oil and gas companies to choose the best prospects and drilling options, with a clear understanding of geological and economic chances of success.

Enhancing seismic data to reveal the best drilling targets is key given the complex geological environment and salt geometries that often mask potential deepwater targets and affect image quality. The seismic data also provide overburden information as well as foresight into possible geomechanical issues, which account for 40% of all drilling incidents. Wider azimuth surveys image subsalt, advanced raytracing algorithms return energy sources correctly, and prestack gathers help interpret poorer data quality areas to illuminate subtle targets and further reduce uncertainty.

This basin-to-prospect assessment is accomplished within the Petrel E&P software platform, which supports integration of basin analysis, prestack interpretation, geomechanical information, and economic analysis in a single environment.

Offset well information is then analyzed within the well-bore software platform to provide context for well planning. The velocity model used for interpretation and modeling is refined and continues in real time while drilling the first exploratory wells. Due to the pore pressure anomalies and irregular drilling conditions expected, a huge focus is placed on the geomechanical model. Even at this early stage the engineering team begins to create a concept design of how the field, if proven, will be developed.

Earth model uncertainties are analyzed in the E&P software platform using specific reservoir simulation software. Optimization and experimental design techniques allow rapid analysis of multiple realizations to evaluate numerous development alternatives – with a clear understanding of the uncertainty related to reservoir properties, volumes, and the potential number of wells required. Using integrated Microsoft communication technology, the drilling team joins the collaboration space in the E&P software platform environment to discuss and review potential well plan options.

Well and network planning

The earth model’s geomechanical components allow the well planning team to easily establish the optimal geometry for initial wells. The trajectory is optimized based on pore pressure information to maximize the safe drilling window and optimize well and casing design. Pore pressure information combined with lithology, stresses, and fluid behaviors establish the expected ROP – allowing users to better understand whether ROP fluctuations are due to lithology changes or drill bit failure.

Real-time information enables drillers to geosteer and monitor formations to adhere to the optimized trajectory and honor formation changes as they drill. Predictive capabilities using look-ahead drilling tools assist when crossing high-risk areas such as over-pressured zones or areas of high instability. The collaborative model is automatically updated with real-time formation data, and properties are redistributed and calibrated using seismic attribute data. The reservoir engineering team can now establish the required number of wells and their locations to successfully develop the field using optimization routines.

Offshore deepwater operations now legally require relief well contingency plans and kick-tolerance models. Drillbench drilling operations software and dynamic multiphase flow simulators are used to design and model wellbore and mud system dynamics. Well integrity planning includes an evaluation of realistic potential blowout scenarios, blowout flow simulations, and relief well constraints for intersection and kill operations. Drilling operations software can be used to design these plans as well as to evaluate potential technical and logistical problems.

The production team creates multiple models for the wells and flowlines to evaluate design alternatives. Initial casing design, flowline sizes, routings, and associated facility requirements are estimated based on expected production rates, fluid types, and production system constraints. Nodal analysis is run on each well to design the preliminary lift system specifications.

Ensuring flow in deepwater environments requires designing and operating facilities within given tolerances such as temperature, pressure, fluid composition, and seabed topography changes. This allows users to plan for all likely eventualities, not just intervene when a problem occurs. OLGA flow assurance simulation software allows detailed flow modeling, incorporating dynamic flow phenomena. Understanding dynamic fluids behavior is critical in subsea environments. Given that long multiphase flowlines are commonly exposed to extreme temperatures, simulation of transient conditions to inhibit hydrates or other solids formation is imperative in the overall system design.

Production advantages and beyond

Production operations software gathers, cleanses, and aggregates all operational data types and events, including measurements from real-time SCADA systems. It transforms data into visual information, allowing engineers to monitor operations from well tests and allocated volumes to the performance of electric submersible pumps (ESPs) to the levels of potentially erosive sand production and indicators on the condition of wells and equipment.

Flow models built in multiphase flow simulation software during the development phase are continuously updated with high-frequency measurements by the production operations platform to reliably identify the causes of production problems. The same data can be visualized in oilfield management software where production engineers can assign appropriate well decline rates and decide when artificial lift or secondary recovery methods are required. Sensitivity tools in flow simulation software define the number of ESP stages required to optimize production. Multiple scenarios are modeled to produce the optimal pump configuration. Performance can then be monitored and modeled to predict failures and issues.

Accurate monitoring and forecasting allows the appropriate allocation of capex and opex through the life of the field in dedicated planning, risks, and reserves software. Actual production data are brought back into the E&P software platform to update the history match of the reservoir model.

Approaching a deepwater project from exploration to production using a fully integrated software system with predictive modeling significantly mitigates the inherent risks. From the first tentative exploration stages to planning artificial lift requirements and optimizing production long-term, software can be used every step of the way to ensure operators get it right the first time.