As the search for hydrocarbons increasingly requires drilling and production in challenging environments, the associated risks are magnified. This is particularly relevant in the current climate of $50 oil, where significant pressure is placed on realizing value and maintaining positive cash flow against reduced revenues. The sheer volume of data that now needs to be processed and the pace of operations in today’s competitive marketplace also can present a challenge.

Successfully executing any oil and gas project—regardless of market conditions—requires input from a range of specialists whose expertise is needed at various stages of the E&P life cycle. With current industry pressures resulting in much tighter financial margins, the development and implementation of more cost-effective methodologies is proving to be critical.

Increasingly, specific technical capabilities are being used to improve the efficiency of a development, reducing risk and optimizing well productivity. This in turn can improve the return on capex and opex while maintaining safe and efficient operations.

Specialist input
In a typical oil and gas field development, production optimization begins once the exploration and appraisal stages are complete. Ideally, specialist input is required early in the well planning process and continues through to assisting with completion design and well construction. Experts in niche specialties such as core analysis, geomechanics, formation damage, production technology, drilling optimization, computational fluid dynamics (CFD), well and reservoir engineering, advanced drilling techniques and well integrity are among the technical authorities sought by most operators looking to optimize well production.

Independent experts in areas such as core analysis or production chemistry are absolutely capable of delivering an effective and technically accurate service. However, a more efficient offering can be demonstrated in terms of value with an all-inclusive approach—looking at and considering the impact of the whole project as opposed to concentrating on particular elements. Collaboration between the technical disciplines can only improve efficiencies.

Sand production
One recent study demonstrates the application of this integrated process. The risk of sand production coupled with the potential erosion issues arising from a combination of high gas flow rates and sand production in the wellbore and facilities components were evaluated. Two engineering studies were undertaken to evaluate the geomechanical strength of the producing formations, select the most appropriate sand mitigation strategy and identify the potential erosion issues at various critical points in the production network.

This incorporated a CFD modeling approach using Lloyd’s Register Senergy’s Wellscope to rank the relative erosion risks in various well components and calculate the corresponding erosion rates for a range of operating conditions.

It was identified that although the intact rock strengths were relatively high, there was a rock strength reduction in the presence of brine, likely related to the fines content of the rock, clay-water interactions and capillary force reduction.

The well component erosion modeling study conducted in parallel with this work indicated significant erosion potential at the wellhead choke, effectively ruling out surface sand management as a viable option. A comparative/screening analysis considered various active sand control techniques and, in light of the formation properties as well as completion and production conditions, two methods were recommended: standalone control using premium or ceramic screens and a chemical consolidation treatment. In addition, since both of these techniques could be conducted through tubing without the need for a major workover, the economics
were considered favorable.

Finally, the study modeled the gas velocity in the tubing, the subsurface safety valve and the choke, concluding from detailed solids erosion modeling that the choke cage suffers the most metal loss when the choke is fully open. Simulation results suggested that a 14% choke opening has the least metal loss on the choke cage. While minimizing the volume of sand produced would reduce the erosion risk identified, reducing the gas production rate by closing the choke also would reduce the erosion risk, although this would of course impact hydrocarbon production and revenues.

Choosing the correct fluids
In another example, an initial appraisal well drilled in the southern North Sea produced only 85 Mcm/d (3 MMscf/d) and effectively condemned the discovery to be nonviable. The operator subsequently relinquished the license. The new field operator commissioned an integrated reservoir study, which demonstrated that the poor well productivity and high-interpreted skin factors were due to exposure of the reservoir formation to water-based drilling and completion fluids, which caused extensive formation damage as a result of water retention, fines migration and solids mud invasion.

Following extensive geomechanical analyses to ensure formation integrity during drilling, testing and core testing to optimize drill-in fluid design and performance, a comprehensive plan was developed to access the hydrocarbons using best practices in well construction and completion design.

The second appraisal well, drilled at lower overbalance using a specially designed oil-based mud system, was tested at 498 Mcm/d (17.6 MMscf/d) with low skin factor and no sand production, in line with expectation. In the absence of significant formation damage,
the absolute open-flow potential was increased tenfold compared to the original well test.

The recognition of the true reservoir potential by the new operator and the integrated formation damage mitigation methodology opened up a significant development opportunity that turned an unwanted asset into a commercially viable development, valued at about $500 million in a subsequent acquisition.

Well construction
A further example is from a well construction perspective. An integrated drilling support team was requested to provide pore pressure and drilling optimization support during a 2013 drilling campaign in West Africa. During the drilling campaign, three deepwater wildcat exploration wells were successfully drilled to total depth. There was considerable uncertainty in the possible pore pressure and other issues such as shallow hazards, which could give rise to drilling risks.

With operational support the well was navigated through pressure ramps and the mud weight kept within the correct range for kick prevention and trip margins.

In addition, drilling ROP restrictions were removed from all hole sections following a hole cleaning review. Every section was completed in line with the planned one-bit run strategy through complex geological settings. The benefits in this case were more than
$2.7 million of savings and a collaborative technical environment where the drilling team worked closely with the more specialist disciplines to the benefit of the project.

By having a greater understanding of the whole project and the challenges being faced in other specialist areas, a more cohesive solution can be delivered. Working closely together from the early well planning phase allows efficiencies to be realized almost immediately. In addition, using collective knowledge across disciplines affords a greater opportunity for ensuring a timely construction phase, which can allow production to begin earlier with minimal impairment to reservoir productivity.

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