Optimization of crude oil production depends heavily on crude oil composition and its variation within individual reservoirs and across multiple reservoirs. In particular, asphaltene content has an enormous impact on crude oil viscosity and even the economic value of the fluids in the reservoir. Thus, it is highly desirable to understand the primary controls on crude oil composition and asphaltene distributions in reservoirs. Here, a complex oilfield in the North Sea containing six separate reservoirs is addressed. The crude oil is believed to have spilled out of deeper reservoirs into shallower reservoirs during the overall reservoir charging process. Asphaltene content is measured in-situ through downhole fluid analysis and is generally consistent with a spill-fill sequence in reservoir charging. Detailed compositional analysis of crude oil samples by comprehensive two-dimensional gas chromatography (GC×GC) is used to determine the extent and variation among the reservoirs of water washing, biodegradation and thermal maturity. Increased biodegradation and water washing in the shallower reservoirs is consistent with a spillfill sequence. The water washing is evidently assisted by biodegradation. Moreover, analyses of four thermal maturity biomarkers show that shallower reservoirs contain less mature oil, again consistent with a spill-fill sequence. The combination of DFA for bulk compositional analysis and GC×GC for detailed compositional analysis with geochemical interpretation is an effective tool for unraveling complex oilfield scenarios.

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Recently, there have been significant enhancements for well control training. Accidents have motivated and necessitated this improvement. As a result of accident investigation, the IOGP (International Association of Oil and Gas Producers) recommended to define, develop and implement enhanced technical and behavioral practices for well control training coupled with evaluation and certification of the recognized industry certifying bodies. Implementation of these recommendations and improvements is the topic treated in this paper. These enhancements address best practices and add the topic "human factors" to the course. Human factors refer to situational awareness, decision-making, teamwork and dynamics, leadership, communication and performance shaping factors. This paper also outlines traditional well control training. Traditional well control training has typically four levels, each with its own materials, and thereby targets various drilling professionals with different roles on the rig. The highest level course is designed for supervisors, and is required in order to participate in the new IWCF (International Well Control Forum) accredited Enhanced Well Control course. The Enhanced Well Control course has been developed with the accreditation body (IWCF), a drilling contractor (Seadrill) and a training provider (Maersk Training). Having representation of these three entities maximizes the effectiveness of this training in that the interests of the end user, the accreditor and, of course, the service provider are all met within a common and agreed upon framework. Enhanced Well Control incorporates expanded scenarios (setting of cement, running casing, and unconventional well kill methods), specific practices and exercises and behavioral responses. Many topics are covered with focus on teamwork, leadership, decision-making and situational awareness. Case studies and customized scenarios are also treated. These developments in well control training provide a safer and more productive drilling environment.

Typically the reservoir evaluation in deep water wells (DWW) drilled by Petroleos Mexicanos (PEMEX) in southern Gulf of Mexico has been made conventionally using Drill Stem Testing (DST) operations that can take up to 23 days. This represents a significant investment in cost and time to the operator in their effort to evaluate reservoirs. The challenge was to evaluate more accurately and efficiently to reduce costs and improve reservoir characterization in these deepwater plays. In this paper, wireline formation testers (FT) are used in openhole DWW for a variety of applications including characterization of the fluids and determination of key reservoir parameters by interval pressure transient testing (IPTT), also referred to as a mini-DST. Real-time monitoring, analysis and job optimization by senior technologists are essential steps in performing a successful logging program. Historically, the wireline programs to evaluate the zones of interest in the Tertiary approximated 8 days that included several gas zones. The new protocol brought an operational advantage to PEMEX by reducing the time required to identify and characterize zones of interest compared with conventional methods. The results included optimization of the production test programs and reduced time/costs for the well production testing stage. The project has four major steps: The first stage includes the identification of gas bearing sandstones and will determine the preliminary program. The highly laminated structures are evaluated with special wireline logs that include nuclear magnetic resonance (NMR), high resolution imaging and elemental capture spectrometry. After the zones are identified, the pressure profile will be analyzed with a PressureExpress (XPT) tool that is wireline combinable and allows for efficient pressure formation testing. In the second stage, the pressure gradients are evaluated resulting in fluid types in the reservoir and mobilities for each flow unit. These results will be used to define the Mini DST stations. The third phase involves the use of the Modular Formation Dynamics Tester (MDT) with the Live Fluid Analyzers (LFA) to characterize the fluid type in each layer. Formation fluid samples are taken according to the program’s acquisition priorities. The dual packer MDT module allows for isolating each individual layer to perform mini-DST’s that can be used to evaluate and determine the formation’s permeability and skin factor. Finally a nodal analysis was performed using the permeability values from mini-DST. The results showed very good agreement between the rate predictions from the MDT fluid and pressure data versus the conventional DST results. This helped Pemex in strategic forecasting of production rates and reserves classification while saving rig time.