Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.
Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.
Here we show that pre-flush inorganic ions (Na+ and Ca2+) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.
This award is intended to acknowledge the section and YP committee officers for outstanding efforts in the areas of interest to young professionals and other industry newcomers. The award will be given in three categories: - Overall Excellence - Most Improved - Most Innovative Winners will be announced at the President's Luncheon at SPE's Annual Technical Conference and Exhibition (ATCE). Plaques will be presented to the YP committee and section officers. Please note that the award for Outstanding Section YP Committee does not replace the President's Awards for Section Excellence. To be considered for this award, the section YP committee chairperson should complete the form below and send it to the section chair for submission with the section's annual report.
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
More than 60% of gas reserves in the Middle East region are regarded as sour. The development of sour oil and sour gas fields or originally sweet oil fields, which undergo a souring process during production live, impose significant investments for the H2S treatment and increase significantly the field operation costs. In order to evaluate the origin and development of the H2S in a production system multiple locations covering all process stations such as down hole, well head, separators, gathering stations, pipelines have to be sampled an analysed. The in-field measurements of the H2S concentrations and various laboratory analyses like S34 / S32 isotope ratio, CSIA, DNA sequencing, MPN and Bacterial growth tests could be performed in order to provide a conclusive picture of the H2S contamination.
The most promising and cost efficient technology is the analysis of the bacterial activity using DNA analysis and bacterial growth tests. The integration and interpretation of all above mentioned analysis types is key for the evaluation of the origin and development of the field souring process and provides a robust analytical basis for remediation, scavenging and mitigation operations. In combination with modern dynamic reservoir modeling tools, which allow the history match and forecast of the field souring process, the efficiency of mitigation or scavenging operations in the subsurface and at the surface can be simulated and optimized.
In context with the envisaged production enhancement, the application of EOR technologies and the souring of several reservoirs due to injection, the monitoring and handling of additional H2S production become an important environmental and economic factor.
Numerous oil and gas reservoirs in Kuwait are suffering from H2S contaminations. The H2S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H2S concentration levels are related to the generation processes. The high H2S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H2S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H2S contaminations observed in the Cretaceous reservoirs show indications of multiple H2S sources. The bulk of the H2S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H2S migrated from deeper horizons e.g. via faults are observed.
H2S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H2S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed.
New sampling and analytical technologies tailored to the H2S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation.
Reservoir modeling and forecast technologies have been developed to predict the development of the H2S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H2S generation process is essential. Furthermore good quality and reliable H2S measurements are mandatory for the history match.
The mitigation and remediation of H2S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H2S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H2S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H2S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs.
In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H2S production, a contry-wide coordination of the treatment concepts for the H2S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.
The Agbami field is one of the largest producing deep-water assets in Nigeria. It was discovered in 1998 and put on stream in 2008 with the field development staggered into three phases. Adopting a phased approach has eased the burden of project management and allowed the Asset team incorporate the key learnings of each phase into the subsequent phases while reducing uncertainty and improving decision making to derive maximum value from the asset. With the third phase of the field development approaching its later stages, it became necessary for the Asset team to take a second look at the wealth of data that had been gathered in the 7 years of production and reevaluate the subsurface understanding with a view to identifying bypassed or unswept oil that could potentially increase recovery from the reservoirs. Uncertainties are inherent in every project and the Agbami project is no exception being a major capital project with its fair share of uncertainties.
Olatunde, Folarin (Chevron Nigeria) | Adeyinka, Adeboye (Chevron Nigeria) | Lawal, Olumide (Chevron Nigeria) | Iyiola, Sunkanmi (Chevron Nigeria) | Faparusi, Dan (Chevron Nigeria) | Bodunrin, Abiodun (Chevron Nigeria) | Sustakoski, Richard (Chevron Nigeria) | Ebo, Henrietta (Chevron Nigeria)
Time-lapse seismic survey also known as 4D seismic has established itself as a useful tool for reservoir monitoring and has gained wide acceptance within the industry. Technological advancements in the area of acquisition and processing have further strengthened the case for its application.
The recent 4D seismic acquisition and interpretation in Agbami has proven to be an economically viable means of adding tremendous value to an oil field irrespective of the development stage it is in, and has been an excellent enabler for reservoir surveillance and resolution of subsurface uncertainties.
Effective management of a field such as Agbami requires a surveillance method which can provide insight into spatial fluid movements with time, which the traditional surveillance methods are unable to provide. This type of insight is required to support sound reservoir management and field development decisions which Agbami 4D seismic provides. The information from the Agbami 4D monitor has shed more light around the fault network architecture within the field and has validated and in some cases changed some of the initial assumption around the sealing nature of these faults.
Also, originally planned drilling locations and completion strategies have been modified based on the insight from the 4D seismic. The 4D seismic has also created value in the calibration of the reservoir simulation models and the location of bypassed oil within the field for future infill drilling. Forward modeling of expected seismic response based on proxy simulations helps to set realistic expectations of what can be seen in 4D seismic data. This paper discusses the acquisition, processing and interpretation of 4D seismic surveys in Agbami and how this information is being used to maximize the value in the field for the stakeholders.
Ultra tolerant coating technology: the 15 years path from maintenance to new construction Joao Azevedo Sherwin-Williams Tower Works, Kestor Street Bolton BL2 2AL United Kingdom ABSTRACT In offshore context, maintenance coatings do not aspire to "high durability" status. New construction protective coating processes, aspiring to such status, often fail to deliver it. The "high durability" aspiration, still, produced a divide between surface tolerant materials for maintenance and new construction coatings: different materials, surface preparation methods and pre-qualification protocols. Four questions may come to mind of an optimistic coating formulator or a demanding offshore owner: 1) can a tolerant maintenance coating deliver high durability despite the less favorable conditions in which is applied? The answers are based on evidence built for 15 years over more than 15 million square meters of steel, witnessing the testing, selection, application and real life performance of a specific surface and humidity tolerant coating technology in marine and offshore maintenance and new construction projects. New data is shared on tolerance to poor surface profile, flash rust and damp & cold conditions and on cost impact when associated with water jetting as surface preparation method. High durability INTRODUCTION By often using the term "high durability" of protective coatings in the offshore context, this paper should start by define it.
Studies of petroleum reservoirs are based on a multidisciplinary integration focused on developing 3D models that honor reservoir heterogeneities; the sedimentological and stratigraphic models play the most important role to honor these heterogeneities; in order to obtain good models it is important to acquire and integrate the highest volume of well data, preferably state of the art technology. This paper presents how electrical log-core data integration obtained a correlation between lithology, lithological accessories, sedimentary structures, structural features, fossils, ichnofossils and fluid impregnation, among others, from the interpretation of two hundred and twenty nine feet of a sedimentary sequence within core data and a high-resolution acoustic-resistivity image log from well DN-22 in Drago field. High-resolution borehole image logs are much more cost effective as compared to coring and subsequent analysis.
From the analysis of the features associated with rock factory (grain size, sorting, roundness) and other associated features like sedimentary and post-sedimentary processes (lithological accessories, fossils traces, diagenetic features), sedimentary facies were identified, which were correlated and adapted to existing sedimentary facies catalog and used for Drago field. Likewise, based on patterns and characteristic responses seen in resistivity and acoustic image log (coloring and shading contrast, texture, clasts, clay laminations, fossils traces, fossils), electrofacies were identified and framed into the same facies catalog. The resulting analysis established eight sedimentary-electrofacies, this contributes to further extrapolate detail sedimentological analysis for coming wells in this field by using high-resolution image logs. This study is unique in the area and will help to better characterize rock properties for field development.
GOWell’s latest-generation magnetic-thickness-detector (MTD) tool is capable of evaluating quantitative thickness measurements of three concentric pipes. The instrument combines a high-power transmitter, improved signal/noise electronics, and fully configurable acquisition. This flexible approach allows a wide range of evaluations under different conditions and conveyance systems, including logging in large pipes (up to 18⅝ in.), fast logging of single pipes, chrome- and alloy-pipe evaluation, thick casings, and memory-optimized logging. Internally, the tool acquires up to 300 channels of pulsed-eddy-current transient decay that can be transmitted in real time to surface or stored downhole. Real-time logging is possible either in combination below any of GOWell’s existing Multi-Finger Caliper (MFC) tools or when combined with PegasusStar, GOWell’s high-speed telemetry system.