Summary Addax Petroleum's operated Okwori oil field, offshore Nigeria, illustrated the benefits of reviving shelved projects, because of an insufficient return on investment using more traditional approaches, by applying more recent technical and contractual solutions. The Okwori project demonstrated the feasibility of developing small and geologically complex offshore oil fields in medium water depth of 440 ft with subsea technologies traditionally used for large fields. In the subsurface, the Okwori wells combined multiple selective completions hydraulically controlled from the surface with expandable sand screens as the downhole sand exclusion solution. This combination of equipment in subsea wells used to fully develop a small offshore oil field marked another technological first in Nigeria. Far away from pre-existing facilities and with less than 50 million bbl of median technical reserves at the time of project sanction, the Okwori oilfield development went a step further than the more usual subsea tieback to a pre-existing offshore production facility. The Okwori development plan was based on horizontal subsea trees flowing to a leased spread-moored floating production storage and offloading (FPSO) vessel by means of (6-in.) flexible subsea flowlines and risers. The Okwori leased production facilities had a built-in capability for additional tiebacks such as the Nda oil field, whose development was completed in October 2006, or for later redeployment in other parts of the acreage depending on further exploration and appraisal drilling. A review of the field operations to date highlighted a steep learning curve in the formulation of completion design, completion fluids, stimulation, downhole sand exclusion systems, and bean-up/bean-down procedures. Introduction The Okwori oil field (OML 126) was discovered offshore Nigeria in 1972, approximately 50 miles southwest of the city of Port Harcourt (Fig. 1). Despite a prolific initial well test, subsequent field appraisal revealed a complicated geological structure and fluid distribution with fragmented hydrocarbon pools of limited extension. The Okwori field therefore remained dormant until Addax Petroleum Exploration (Nigeria) Ltd. acquired the asset in 1998 and provided a development plan. Okwori field development drilling started in July 2004 after drilling ND-1, the Nda oilfield discovery well located due west of Okwori. Okwori first oil was delivered in March 2005 as planned. Subsurface Critical Success Factors In the subsurface, Okwori's main challenge was the large number of reservoir layers and fault-delimited compartments resulting in numerous potentially hydrocarbon-bearing pools. More than 100 of those pools were mapped from two vintages of 3D seismic surveys; before field development, six wells appraised 30 such pools (Fig. 2). The Okwori structure resulted from a collapsed crest anticline with two intersecting sets of syn- and post-sedimentary fault planes (Fig. 3). It was noted that seismic imaging was of poor quality owing to the convergence of multiple faults in the core of the collapsed crest and the presence of shallow gas accumulations. Appraisal well trajectories were designed to scoop reservoir closures against fault planes. Hydrocarbon content (oil or gas) and fluid contacts differed between compartments of the same reservoir level, adding another level of complexity to the development. Risked oil-in-place volumes were computed to rank reservoir targets and guide the field development. Each development well was considered as an appraisal well for which the decision to complete any reservoir level would be taken after drilling and logging the well. It was also clear that the size of these hydrocarbon pools would seldom justify more than a single producer per pool. Nigeria petroleum law specified a minimum distance of 800 m between two drainage points in the same hydrocarbon pool, which in Okwori meant only a single possible completion per pool. Pressure maintenance through water or gas injection would require additional wells, a situation neither financially attractive nor technically desirable because of the small dimensions and compartmentalization of the oil rims. Finally, the Okwori reservoirs were made of unconsolidated sandstones from the Niger Delta that required some form of sand control.
Low resistivity low contrast (LRLC) reservoirs have been successfully produced for many years; however detection and detailed description of their properties and potential would remain a challenge in absence of an exhaustive formation evaluation program. Proper understanding of the geological evolution of such reservoirs to explain their distribution and variations in petrophysical properties is also vital. Low resistivity pay reservoirs encountered in West Africa are often characterized by variation in resistivity values in vertical and horizontal directions due to fine grains and conductive layers within the coarse grained sands and clearly marked sand-shale laminations. This is accurately solved by tri-axial induction resistivity measurement in combination with high resolution measurements able to define any contributing layer level-by-level through robust anisotropic interpretation methods. However, heterogeneity, mixed clays effect, and complexity in rock texture require new technology and innovative interpretation models in multi-domain approach. Advances in logging technologies, interpretation software, and analytical methodologies enable better and more refined reservoir models to be fashioned and tweaked as needed on a case-by-case basis. The case study analyzes log responses, implication of heterogeneity and mixed clays content on the generation of LRLC pay reservoirs in deltaic environment offshore Nigeria. Precise application of advanced log measurements and integration of core data in a common workflow, built around the concepts of evolution of LRLC reservoirs lead to accurate pay quantification. Borehole image interpretation suggests that the low resistivity contrast is attributed to dispersed clays coating around the sand grains in the toe part of a delta front in major coarsening up and feeble fining up sequences. This is also confirmed by variations of elastic properties of the matrix. Petrophysical logs recorded at high resolution correlate inferring the main causes of LRLC pay are clay content and distribution, and small grain sizes intermingled to the reservoir rock, hence resulting in low resistivity values in all directions and drastically increased irreducible water. The logs based model is confirmed by calibration to core analysis results. The confident results of the study confirm the power of collaboration between petrophysics, rock mechanics and geology in innovative interpretation workflows for enhanced reserves estimate and Producibility prediction in heterogeneous media.
A comprehensive petrophysical and fluid distribution evaluation is crucial for optimal reservoir management. Conventional measurements to determine the presence of movable hydrocarbons, qualitative producibility and in situ reserves estimation have proved to be inconclusive in several fields in West Africa due to presence of thin-beds, dispersed clay and highly variable water salinity. The case study presented demonstrates that the constraints of the conventional measurements can be overcome and highlights the benefits of the following multidisciplinary approach: Tri-axial array induction, spectroscopy, and neutron-density identified the potential hydrocarbon bearing zones. Advanced magnetic resonance provided key measurements by continuous scanning of the formation properties to correctly identify the reservoir fluids and contact levels and to reproduce variations radially into the formation. Regardless of variations in formation water salinity or low contrast pay. Optical spectroscopy coupled with fluorescence and reflectance identified the full characterization of the formation fluid, both composition and phase behavior. This allowed identifying the different types of hydrocarbons (gas, light and dark oil), independently from their level of saturation. In combination with magnetic resonance fluid maps, this gives an insight on original fluid in place, and change of phase is properly described. All this information is key to define future field development strategies. This case clearly demonstrated the benefits of an integrated use of innovative wireline technologies and expert processing methods adopting a multidisciplinary approach for accurate reserves estimation.
An intelligent Petrophysical evaluation is essential to optimize development and production in difficult environments in the Niger Delta because of the challenges in reserve estimation and development strategy. The areas are typically characterized by unconsolidated and laminated sandstones and fluvio-marine or lagoonal shales, where accurate estimation of hydrocarbon saturation and consequently volumes has continued to be a challenge in the evaluation of these shaly sand sequences. Most shaly-sand formations have poorly developed sand packages containing laminations of fine grained rock which cause resistivity values to vary in vertical and horizontal directions (Rv & Rh) masking the resistivity contrast when using conventional induction resistivity measurement. The use of a tri-axial multi-array induction tool overcomes the limitation of a standard induction measurement to account for properties of thin beds and complex dipping formations. The challenge of interpreting low resistivity contrast sands lies on determining the actual resistivity of coarse grained components and addressing the volumes of fine grained components in the formation which in the past have been a very cumbersome process. However, the application of advanced interpretation workflows to determine the fractional volume of fine grained rock alongside resistivity of coarse grained rock using matrix corrected porosity, vertical and horizontal resistivity measurements enables a quick and easy approach towards estimation of hydrocarbon volumes. This paper presents an integrated approach for accurate hydrocarbon volumes estimation using triaxial induction measurements of horizontal and vertical resistivity, formation dips and azimuth,, elemental yields from the nuclear spectroscopy tool to quantify mineral volumes with traditional environmentally corrected neutron-density measurements and validation with fluid samples. Comparison of results with conventional approach show over 50% increase in net pay which points to the implication that a good percentage of wells drilled in the past and analyzed using conventional methods either by-passed or under-estimated hydrocarbon reserves.
Future energy sources will come from their discovery by accepting more risk in exploration under tough drilling and logging conditions. In many fields in Nigeria, determination of producible oil and gas and in situ reserve volumes has proved too difficult for conventional, old vintage, logging suites. The complex mineralogy, presence of thin shale laminations and grain size variations within the sand bodies and very low and variable formation water salinity, require the use of advanced logging and conveyance technologies for accurate reservoir evaluation. Advanced magnetic resonance wireline measurements provide a solution to evaluate reservoir quality and hydrocarbon systems potential. This technology is able to reveal a multitude of reservoir and wellbore properties supported by innovative signal processing and interpretation capabilities. This enables capturing essential information for multiple applications providing formation evaluation solutions unaffected by well deviations and borehole rugosity. Continuous fluid characterization at multiple depths of investigation in a single logging pass from the advanced NMR tool resulted in correctly identifying the types and volumes of the various reservoir fluids and their contact levels. The case study presented in the paper demonstrates the benefit of using advanced magnetic resonance in complex formation and in tough logging conditions where conventional measurements were inadequate. A major challenge in these reservoirs was the identification of the fluids contact, which was masked by poor resistivity contrast between oil and fresh formation water. In addition, the poor borehole conditions, severe enlargement and high rugosity, made it impracticable to successfully complete a planned wireline formation testing program. The excellent data quality and reliability of the advanced magnetic resonance answer product despite the near wellbore damage and invasion effects proved that advanced magnetic resonance is a practical choice to provide accurate hydrocarbon volumes and in-situ fluid analysis to complement or fill the gaps in petrophysical and fluid sampling program in challenging complex and rugose borehole.
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