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Koksalan, Tamer (ADNOC Onshore) | Ahsan, Syed Asif (ADNOC Onshore) | Azouq, Youcef (ADNOC Upstream) | Alhouqani, Shamsa Sulaiman (ADNOC Onshore) | Al Blooshi, Ahmad (ADNOC Upstream) | Ali Basioni, Mahmoud (ADNOC Upstream)
Oil leakage, due to well integrity issues of varying proportions, from downhole completions is a common phenomenon despite all measures and adherence to regulations. These leakages potentially could cause environmental damage through surface spill, aquifer contamination and in worst-case scenario loss of human lives. In an offshore setting, impact of well integrity issue can be more severe than in an onshore well due to complex and often costly offshore well operations. Downhole completions including cement quality deterioration occurs with the passage of time due primarily to corrosive nature of hydrocarbons produced from a well. Oil companies perform routine well integrity surveillance by acquiring real time annulus pressure data, cement bond, temperature and sonic logs to assess well integrity and perform remedial measures, if and when, required. Leakage may also occur in a complex pattern from nearby wells and different reservoir than the suspected reservoir and show up in the annulus or eventually on the surface. Whilst, well integrity surveillance data indicates leakage when it occurs, finding the exact source location of leakage is often difficult. Objective of this study was to perform a cost-optimized reservoir to annulus leakage oil correlation using geochemical methods in an offshore well to establish the source of oil in the annulus.
Shoup, Robert Charles (Subsurface Consultants & Associates, LLC) | Jong, John (JX Nippon Oil & Gas Exploration Malaysia Ltd) | Barker, Steven M. (JX Nippon Oil & Gas Exploration Malaysia Ltd) | Khamis, Mohd Asraf (JX Nippon Oil & Gas Exploration Malaysia Ltd)
The high cost of deepwater developments and the limited reach from offshore platforms requires operators to have a good understanding of the expected reservoir compartmentalization in the field before the first well is drilled. Deepwater reservoirs can be compartmentalized both structurally and stratigraphically. This paper will briefly address the structural compartmentalization and discuss the stratigraphic baffling that occurs in deepwater depositional settings.
The distribution of reservoir facies within deepwater depositional settings is well-understood from outcrop studies, seismic facies mapping, and exploration and development drilling. This understanding can be used to predict where stratigraphic compartmentalization is likely to occur.
Channel levee complexes and crevasse splays are deposited principally on the slope. Deposits are typically characteristic of a meandering river. Fluid flow in channel levee complexes occurs principally along the channel thalweg. Small-scale slumps within the channel levee complex may baffle flow from the levee into the channel thalweg. Crevasse splays are deposited when there has been a breach in the levee. The reservoir distribution in a crevasse splay deposit is characteristic of a river-dominated delta. Fluid flow in a crevasse splay will be generally toward the channel breach.
Submarine fans are deposited in structurally restricted basins on the slope or on the basin floor. Interbedded shales baffle vertical fluid flow, with lower or distal lobe deposits more vertically baffled than upper lobe deposits. Lateral baffling of fluid flow in lower fan deposits is generally caused by small faults. In the middle to upper fan lateral erosional channels as well as small faults can baffle lateral fluid flow.
Gorges or canyons are incisional events. They can occur anywhere on the system but are more common and more deeply incised in the upper fan and slope. The reservoir facies that fill the gorge are typically sand-prone, with sand more prevalent in the lower gorge-fill.
Debris flows and slumps can occur anywhere in the system. Since reservoir connectivity within the debris flow is minimal, these should not be targeted for development.
The objective of this study was to evaluate the role of strategic mergers and acquisition (M&A) as a panacea for success of marginal oil fields development in Nigeria and to make recommendations for policy decisions. Data for the study were obtained from literature review, document analysis and multiple case studies from operating marginal oil field companies in Nigeria. The cases of Platform Petroleum, Sheba Petroleum, Seplat and others were investigated and analyzed. These case studies identified how marginal field operator's utilized mergers and acquisitions in the form of business restructuring, consolidation, strategic alliances, joint venture formation and partnerships as a development support strategy to remain competitive in the oil and gas industry. Other mergers and acquisitions activities by other companies were also examined. The study findings revealed that strategic mergers and acquisition is one of the survival options for marginal field operators in Nigeria. Mergers and acquisitions enhances the business growth for the marginal oil fields operators by expanding the opportunity for raising capital required for oil and gas operations and provision of larger equity base; including provision of access to technology and manpower. As the oil price in the global oil and gas market remains low, investors in oil and gas business are looking for ways to cope with the fall in revenues. In this dynamic business environment, one fact remains unchanged, marginal oil field operators in Nigeria must re-strategise in order to survive. The marginal oil field operators in Nigeria are encumbered by inadequate funds and other constraints such as lack of capacity, low volume of production and inadequate technology, therefore they have to adopt one of the critical success factors for business survival in a challenging environment. Herein lies the role of strategic mergers and acquisitions. The findings of the study will serves as a decision-making frame work for investors in oil and gas business wishing to participate in the sustainable management of marginal oil field in Nigeria. The study recommendations indicate that policy makers in Nigeria should create a favorable investment climate among which are: stable macro-economic policies, legal system that allows contracts to be enforced and clearly support access to channel of arbitration.
Rotary steerable tool has been proved reliable tool that can be used in different types of formation. But in the Rio Del Rey area in the "Benin sand" in Offshore Cameroon, directional drilling issue have been faced while drilling with rotary steerable tool.
This paper present a case of study on the importance of the Bottom Hole Assembly choice versus the lithology, BHA Configuration, bit selection and trajectory requirements. Also based on lessons learned, propose some recommendations.
Rotary steerable is deemed to be a reliable tool that can be used on most of type of formation but this is not always the case as shown in our case of study while drilling through the Benin sand formation which is a shallow formation in Rio Del Rey field in the Niger Delta, offshore Cameroon using the rotary steerable system. RSS BHA has been observed to perform below expectations while drilling this formation. A holistic review of the operational performance of the five Bottom Hole Assembly that was run in the hole to drill ~1000m of soft sandy formation will be summarized. We will analyze each BHA that was ran in hole and the performance achieved. Also BHA configuration and trajectory will be evaluated and reviewed. Finally, some recommendation are made. In addition, the choice of bit selected and performance will be evaluated.
After detailed analysis of each BHA, RSS BHA with PDC bit was seen not to be a good choice of BHA to drill through the Benin sand formation based on the well directional objectives and BUR requirements. Motor BHA with tricone bit using the principle of jetting was used along with catenary design trajectory. This BHA and bit selection choice with catenary design trajectory helped to achieve the directional objective 100%, even exceeded the required DLS at some point. Also, adjusting drilling parameters contributed to the success seen so far.
However, some irregularity was observed in the dogleg severity which may need an additional run with the rotary steerable system to smoothen the trajectory or perform a control trip in this soft formation with the potential risk of accidental sidetrack.
In conclusion, a Motor bottom hole assembly with tricone bit using the principle of jetting should be used if a risk of collision is highlighted and a need to build up quickly in order to move away faster from nearest wells.
A motor assembly is more recommended in soft shallow formation (0m −700m TVD) than the rotary steerable system. A better BUR behavior was observed with a motor assembly.
This paper will serve as a guide / recommendation for any drilling that requireds an aggressive shallow kick off due to collision concern in soft shallow surface formation where performance of the bottom hole assembly and bit selection is critical.
Reservoir fluid characterization is critical to understanding the nature and phase behavior of reservoir fluids. This process has typically been undertaken using laboratory analyses, a time-intensive and costly process which also provides compositional data. Over time, correlations have been developed to predict the PVT properties of crude oil based on parameters such as solution gas-oil ratio, saturation pressure, viscosity, and density. These correlations have had shortcomings such as utilizing a leave-one-out approach, or recently, focused on non-inferable methods such as Neural Networks. This work utilizes compositional data, hitherto neglected in PVT correlations, as input into an inferable machine learning algorithm which can be used to predict PVT properties of crude oil from the Niger Delta basin.
Data containing bubble point pressure, solution gas-oil ratio, and oil formation volume factor alongside composition were obtained and used to develop models. Machine learning model training techniques such as data preprocessing, transformation and hyper-parameter tuning were undertaken. The elastic net regression algorithm utilizing a cross-validation approach was used to develop the models. This ensured an adequate bias-variance tradeoff.
The resulting models were compared with established correlations such as Standing & Katz. Upon statistical analyses performed comparably. The bubble point pressure model, solution gas-oil ratio, oil formation volume factor achieved R-squared value of 0.87, 0.95 and 0.84 respectively on the validation dataset. The models are expressed in the form of equations which can be used in petroleum engineering calculations or implemented in reservoir simulation software. By implementing this approach, a framework for utilizing machine learning for Petroleum Engineering problems which produces inferable results is established. Given potential discoveries in the Niger Delta, upon obtaining compositional data, these set of equations can be used to predict the reservoir crude oil PVT properties, leading to savings in time, cost, and effort, while obtaining actionable and accurate results.
A quantitative seismic interpretation (QSI) approach in assessing reservoir properties of a near-field exploration discovery is presented. This approach demonstrates the integration of rock physics model and seismic inversion to determine the lateral extent of the reservoir complex, improve the understanding of geometry and connectivity of the reservoir sands encountered in this field; and improve confidence in estimates of the resource base. An integrated interpretation approach that incorporates seismic and well log data sets, together with available relevant reports is adopted to reduce interpretation risk inherent with the study location. The hydrocarbon bearing reservoir sands were characterized, based on their elastic rock properties responses, to predict reservoir parameters for reservoir architectural delineation from seismic data volume. The results provide insight to address subsurface uncertainties associated with reservoir connectivity, and future infill well count determination for production optimization and possible reserves addition.
The Well A14 was drilled in 2004 with dual completion and flowed for about 7 years. The well was shut-in due to high water cut and sand production. In December 2011, the well was re-completed single with 7’’ Cased Hole Gravel Pack and ESP + YTool. The well was later sidetracked and deviated to a tie-in point in order to encounter the target at optimal structural positions and provide additional drainage points on the target level to optimize hydrocarbon recovery from the field. The flowed for a period of 2 ½ years and stopped flowing as a result of electric fault on the ESP. Following this and the unfavorable price of crude oil at the time, there was need for an optimized means of intervention; several factors were considered and a HWO intervention using HWPU was selected. This paper addresses the contingent challenges faced and how these were overcome in the course of this 2nd W/O to recover the existing completion and run-in with a new design of ESP and accessories. During POOH the old completion after laying down the D-ESP packer on surface, the well kicked as a result of poor circulation during the killing operation. This resulted in a loss of control and fluid influx spilling to the environment. This challenge was addressed in compliance with the best standards. The W/O was resumed and the entire completion string and ESP assembly + Ytool retrieved. Subsequently during the final installation of the new ESP, the string parted at the threaded connection and the entire ESP completion assembly was lost in hole. This second incident was carefully reviewed by the team involved prior mobilization of fishing equipment and eventual recovery of the lost-in-hole in a single attempt. The entire completion containing the lost-in- hole, on about 2000m of 3 ½" Tubing completion was recovered; the new assemblies were prepared and RIH successfully. The well was eventually completed and currently flowing (≈2000bopd). The responsible team reviewed the incidents, identified lapses and proposed future procedures in order to forestall reoccurrence.
Nosike, Livinus (TOTAL E & P Nigeria Limited) | Uwerikowe, Gabriel (TOTAL E & P Nigeria Limited) | Biu, Victor (TOTAL E & P Nigeria Limited) | Adeyemi, Adeoye (TOTAL E & P Nigeria Limited) | Usman, Musa (TOTAL E & P Nigeria Limited)
Regional studies are known to show major compartmentalization in an oil field, while observations during development and production often highlight local structural connectivity issues that require fault characterization at field-scale to mitigate uncertainty in reserve or stakes. The Akpo field, located in the deep offshore Niger Delta, exemplifies a maturing field where these structural connectivity issues are dominant and play significant roles in field development. Structural discrepancies in the crest and flanks of the anticline result in varying water contacts and overpressure differences, affecting connected volumes and sweep efficiency. Qualitative fault throw analysis, aided by 4-D monitoring results, show that same faults may be sealing and communicating at difference areas, across reservoir fairways in the deep offshore turbiditic channel complexes, delineated as architectural elements. Shale Gouge Ratio (SGR) helps in further constraining the sealing/leaking impact of fault gouge at a log-scale, such that adjacent well data can be used quantitatively to assess preferential flow paths across and within faults zones. This revealed an along-fault, up-fault and across-fault connectivity anisotropy. This work addresses how the fault characterization was used to assess the following: 1. Reservoir compartmentalization, leading to panel separated as fault blocks.
Imomoh, Victor (Baker Hughes, a GE company) | Ndokwu, Chidi (Baker Hughes, a GE company) | Amadi, Kenneth (Baker Hughes, a GE company) | Toyobo, Oluwaseun (Baker Hughes, a GE company) | Nwabueze, Ikechukwu (Baker Hughes, a GE company) | Okowi, Victor (Baker Hughes, a GE company) | Ajao, Oyekunle (Chevron Nigeria Limited.) | Okeke, Genevieve (Chevron Nigeria Limited.) | Dada, Yemi (Chevron Nigeria Limited.) | Jumbo, Sandison (Chevron Nigeria Limited.) | Aina, Soji (Chevron Nigeria Limited.)
Oil and gas drilling has fully embraced the practice of drilling horizontal and extended-reach wells in place of deviated wells to avoid multi-platform drilling and increase hydrocarbon recovery. However, the producer is still faced with multiple challenges that include lateral facies change, lateral variation in reservoir properties and structural uncertainties. Consequently, it is paramount that continuous advancement is achieved in combining fit-for-purpose, real-time logging-while-drilling (LWD) solutions to assist further in the enhancement of hydrocarbon recovery.
Reservoir navigation services (RNS) involve predicting the geology ahead of the bit to place the wellbore correctly in the zone of interest in a horizontal or near-horizontal path. LWD data, obtained from downhole drilling suites, transmitted in real time through mud pulses to a surface computer where the data are interpreted and used to steer the well in the desired direction. Formation pressure while drilling (FPWD) is a process of acquiring reservoir pressures downhole and this is done with a specialized downhole LWD pressure-testing tool. The use of RNS in Well-MX played a significant role in the drilling project – landing Well-MX in the targeted M reservoir bed and drilling the lateral section. The major geosteering technologies used are the at-bit resistivity and azimuthal propagation resistivity, which provides geostopping capability, reservoir bed boundary mapping and accurate distance to bed boundary calculation. These technologies helped in keeping the wellbore within the hydrocarborn unit of the M reservoir. Performing formation pressure testing in realtime, the team was able to carry out a reservoir gradient analysis which helped with reservoir fluid identification, fluid contact determination, and connectivity of hydrocarbon zones before drilling was concluded.
Well-MX is a horizontal well located in the Mirum field of the Niger Delta Basin, offshore Nigeria. The well was drilled to target the deep multi-lobed M reservoir to a total hole depth of 11,307ft MD. By using Well-MX as a case study, this paper discusses how the combination of reservoir navigation service and real-time formation pressure sampling helped meet drilling objectives for this well. Some of the challenges encountered includes vertical seismic interpretation uncertainty, poor reservoir quality along the drain hole section, change in depth of oil to water contact and undulating bed boundaries. Other challenges and decisions taken to successfully geosteer the well will be reviewed in this paper.
The present investigation focused on geochemical evaluation of shale sequences in The Lower Benue Trough using geostatistical approach Thirty two representative samples of shale sequences of The Asu River Group, Nkporo Group and Mamu Formation in The Lower Benue Trough were subjected to Multi-Parameter study in an attempt to present a model of the sediment provenance, and paleoenvironment diagenetic conditions. The X-ray diffraction and Inductively Coupled Plasma Mass spectrometry (ICP-MS) techniques were employed to examine and establish qualitative and quantitative constituents of the Major oxides, Trace and Rare Earth elements.