bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deepwater Nigeria Field Development: Challenges, Best Practices and Lessons Learned from the Agbami Field
Authors: Odusote Femi 
Published: July 2013

Abstract
With potential reserves of about 1 billion barrels of oil, the Agbami Field is one of the largest producing deepwater assets in Nigeria. The field was discovered in 1998 and was put on stream July 28, 2008 at an initial production rate of ~ 95 MBOPD. The field reached peak production of 250 MBOPD on Aug 13, 2009, 4 months ahead of schedule. Agbami is Chevron's first operated deepwater asset in Nigeria and is located 70 miles offshore from the Nigerian coastline at a water depth of about 4,800 feet.
The Agbami subsea development plan consists of 38 subsea wells (22 producers, 11 water injectors and 5 gas injectors) tied back to a Floating Production, Storage, and Offloading (FPSO) vessel via subsea flowlines. The development strategy is to have mid-flank oil production with peripheral water injection and crestal produced gas re injection to enhance recovery from pressure maintenance and improved sweep efficiency in addition to compliance with a "No Flares" policy. The field development plan was optimized to be executed in 3 stages, and is currently in Stage-2 with 14 producers, 3 gas injectors and 6 water injectors already drilled, completed and contributing to the daily production.
2013 will mark 5 years since the Agbami field came on stream. The field has produced about 350 MMSTB of oil as at year end 2012 at a 2012 average rate of 233 MBOPD. The field continues to perform with operational excellence in all areas from safety to production in-spite of the several challenges that are faced on a daily basis. This is as a result of the focus on operational excellence and sound reservoir management practices.
This paper seeks to highlight the performance of the Agbami field to date and demonstrate how a focused reservoir management approach has resulted in the the fields’ world class performance in spite of the challenges faced. The paper will also seek to share best-practices and lessons learned from the Agbami field experience.
Use of High GOR Wells for Artificial Lift in a Mature Field - the OFON Field Case
Authors: Faseemo Oladipo , Odeniyi Akintayo , Onyema Uche 
Published: July 2013

Abstract
In a brown field, the need to have a reliable well re-start and well activation method becomes increasingly important owing to the decline in reservoir pressure and possible heavy hydrostatic column after water breakthrough, leading to re-start and vertical lift difficulties. When this occurs, the well is said to be non-eruptive. The conventional method for solving this challenge is the use of gas-lift activation, which requires a gas source, compressors and scrubbers. Such equipments are currently unavailable on the Ofon field and a different approach to well activation had to be devised.
The Ofon field development plan was in two phases. The second phase, which includes conventional gas-lift activation, was scheduled to commence seven years after the start of the first phase. No provisions were made for conventional gas-lift of wells in the first phase of the project. Unfortunately, the second phase of the project has been delayed for almost 10 years. Consequently, a new approach was devised to restart wells with low eruptivity and artificially lift wells which have lost eruptivity.
The pseudo-gas lift method involves the use of a well with high GOR and high flowing well head pressure (FWHP) to lift another well through a surface pipeline called chicksan. The line is connected to the wellhead of the HGOR well via the swab valve on one end and the other end is connected into the annulus of the well requiring artificial lift. The implementation of this technique is simple and does not require additional equipment. This method has shown to be effective in cases where it is uneconomical to install a conventional gas lift unit, there are space constraints or there is delay in installing a conventional gas lift system as in the case of the Ofon field.
An additional oil production of about 16 MMbbls has so far been obtained from the field with the use of this pseudo gas-lift method. [M = 103].
Promoting Effective University-Oil Industry Research Collaboration In Nigeria
Authors: Falode Olugbenga A. , Nebeife Peter C. 
Published: July 2013

Abstract
Effective Research Collaboration between the University and Industry (U-I) plays a very important role in pushing the frontiers of knowledge and developing new technologies thereby making them powerful engines for innovation and economic growth. Some developed economies have achieved a long-standing tradition of collaboration between universities and industry which maintains a pool of subject-matter specialists within the academic community, ensuring handy solutions to emerging industry challenges, among other benefits. However in Nigeria, there is a growing gap between the academia and the industry. This may have contributed to the low rating of graduates from Nigerian universities in terms of technical competence, as many of the students’ research engagements are not tied to the industry.
This paper therefore aims to examine and evaluate the status of research collaboration that exists among petroleum engineering, geosciences schools and the oil industry, and recommendations to reinforce and enhance the effectiveness of U-I collaboration in Nigeria were proposed.
Joint research projects carried out between selected universities from the six geopolitical zones and the oil industry in the last two decades were analyzed in order to identify the barriers to effective U-I collaboration. Survey questionnaires were developed and administered to faculty members and oil industry managers to elicit the frequency of interaction by types of engagement and barriers. The survey data were analyzed using descriptive and inferential statistics.
The implications of the findings from this study are utilized to recommend policies aimed at facilitating effective U-I collaboration.
Issues, Trend And Opportunities For The Production Of Bio- Synthetic Paraffinic Kerosene (Spk)
Authors: Babatunde A. A , Egmba K. C , Kehinde A. J , Falode O. A 
Published: July 2013

Abstract
Biofuels are increasingly becoming a viable alternative for reducing consumption of petroleum, a policy goal resulting from recent high oil prices, energy security concerns, and climate change. More recently, projects have been initiated to map a way forward for the introduction of sustainable biofuels to help reduce dependence on fossil fuels in air transport and reduce GHG emissions by the air industry. Globally, various feedstocks and conversion technologies for production of biofuels for aviation are currently being investigated. The purpose of this paper is to present issues, trend and opportunities in the production of SPK as an alternative to the traditional fossil fuel. The work focuses on SPK as an aviation fuel with its attendant environmental benefits of reduction in CO2 emission. The paper also reviews different feedstock used in SPK production such as Jatropha, Camelina and Algae. Process technologies used are also surveyed.
Wellbore Stability Management In Depleted And Low Pressure Reservoirs
Authors: Fekete Paul O. , Adewale Dosunmu , Kuerunwa Anthony , Ekeinde Evelyn B. , Chimaroke Anyanwu , Odagme Baridor S. 
Published: July 2013

Abstract
New zones in mature fields continue to be actively developed as operators strive to maintain depleting reserves. Many of the world's new reserves are discoveries made below these existing, mature reservoirs. Drilling activities in or near producing or previously abandoned reservoirs often encounter large variations in pressure gradient as depleted layers or low pressured zones are exposed during the drilling process. Zones with pressures inconsistent with the overburden are often encountered, if conventional drilling techniques are used, then the higher mud weight used to hold back the target interval may result in massive losses (lost circulation), differential sticking, sloughing, or collapsing formations in the lower-pressure zone. There is a clear advantage to drilling if we could drill by reducing the drilling window between pore pressure and fracture gradient, using cage stress (particle bridging) or wellbore strengthen (WS) to drill at higher mud weights without losing fluid. This work presents the approach of WS that can be accomplished with treatment of the whole drilling fluid with Lost Preventive material (LPM) that are designed to seal and effectively increase fracture resistance allowing the operator to drill through a weak formation zone successfully with minimal to zero losses. Other models and materials were also investigated to determine their suitability and operational design parameters. Models for LPM application procedure (minimum volumetric requirements, quantitative requirements for filter cake thickness and optimise hydraulic parameters for effective cake deposition) were developed. The advantage of this process is reduction in drilling difficulties and non productive time for operators. Some experimental work was also carried out to determine the port throat of the formation, particle size distribution (PSD), strength & stability of the LPM filter cake, as well as the compatibility of different LPMs with different mud system. Results from case studies were also presented which shows tremendous result in reduction of NPTs via no loss circulation.
Study of Alcohol Mixtures for Enhanced Oil Recovery
Authors: Ikeagwu C. , Nyah F. J. , Onyekonwu M. O. , Ogolo N. A. , Ubani C. 
Published: July 2013

Abstract
Several techniques have been deployed to enhance oil recovery. Some have given good results while there is still the possibility that some materials that have not been tried might also have the capacity to enhance recovery. The underlying motivation for this study therefore is to find out the capacity of local materials to enhance oil recovery. Alcohol (palm wine) and water mixture and alcohol (palm wine) and starch mixture were used in various ratios to find out the ideal ratios that recovers oil most from sands.
Experimental results show that a mixture of alcohol and water and alcohol and starch can enhance oil recovery. For alcohol and water, oil recovery increased with an increase in alcohol content of the mixture. This could be attributed to reduction of interfacial tension between oil and water. For alcohol and starch, the ideal ratio of 1:1 gave the highest recovery. Beyond this ratio, oil recovery was observed to be reduced. The good result may have resulted partly from reduction of interfacial tension and partly as a result of increase in the viscosity of the displacing fluid.
Depletion of the Knowledge Base in the African Oil and Gas Industry -Women to the Rescue
Authors: Reginald-Ugwuadu Onyinye 
Published: July 2013

Abstract
Growing the African Oil and Gas industry requires a highly skilled and talented workforce for improved innovation and sustainability. With the increased job mobility and migration of the male workforce, it is imperative that the industry considers the emerging dynamics and seek other avenues for growing and securing local talent pool.
The current workforce in the oil and gas industry is predominantly male with a sprinkling of females in the existing talent and skill pool and even fewer opportunities for females in leadership roles. Diversity and inclusion initiative has recently helped to encourage policies that promote some considerations for the female workforce. However, there is still more work to be done.
This paper sets out a discourse on the issues, challenges and prospects for the oil and gas industry in Africa with primary focus on policies that identify and adequately utilize the skills and talents of the female workforce; maximizing their ingenuity in knowledge management and capacity building for the advancement and sustainability of the sector.
The exposition will recommend insightful roadmap towards ensuring consistent retention and improvement of the knowledge base in the industry as well as means and ways of attracting qualified and talented females.
Material Balance Modelling of Hydraulically Connected Reservoirs in a Single System: Case Studies
Authors: Nwaokorie Chukwuemeka , Ukauku Ikwan , Emelle Chima 
Published: July 2013

Abstract
The evaluation of the recoverable hydrocarbon volume and further development opportunities in complex reservoirs (where two or more reservoirs are hydraulically connected) primary challenges the engineer faces in managing such reservoirs. In this study, multi-tank material balance models have been built to solve these problems.
The key criteria for a robust material balance modelling of hydraulically connected reservoirs in a single system are: (i) transmissibility across the reservoirs should be properly defined. Transmissibility is a major modelling component in achieving sound multi-tank MBAL models. It is useful to the estimation of the rate of aquifer movement across the reservoirs. (ii) Good understanding of the geology and production data of the reservoirs is helpful in estimating the appropriate transmissibility. (iii) Sufficient and quality Carbon-Oxygen logs, BHP and production data. CO logs are very important for proper calibration of hydrocarbon contact. Accurate BHP data is critical in the establishment of dynamic communication and matching of simulated versus measured reservoir pressure.
In this paper two cases with over 30 years of production history are discussed in detail including the full methodology and the associated results. The results from these studies show good and reliable outcome which has provided the basis for the reported hydrocarbon resource volumes of the reservoirs (B1.0X, B1.0N, C1.0X, E9.0X, E10.0X, E11.0X, G1.0X, H1.0X)
Results were compared with other methodologies (existing simulation models and DCA of NFA wells) and indicate good comparisons. The number of development opportunities in the 8 reservoirs were optimised from 22 to 20 wells using the multi-tank material balance model.
Despite some known limitations of material balance generally, multi tank material balance model has proven to be a simple and reliable methodology in evaluating complex reservoir system with hydraulic communication. Especially, in situations where time and budget constraints will not support full field reservoir simulation modelling.
Application of Real-Time Fluid Sampling in Mature Fields: Case Study of Oben Field (Re-) Development Planning
Authors: Amedu J. A. , Nwokolo C. E. , Badmus O. M. , Ibrahim A. D. 
Published: July 2013

Abstract
The acquisition and interpretation of cased hole saturation logs is crucial to the effective execution of field development plans and maintaining a top notch well and reservoir management. However cased hole saturation logs in mature field developments characterized by low salinity formation water, saturated hydrocarbon liquids and gas condensates can unfortunately be beset with significant levels of non-uniqueness making it quite difficult to evaluate fluid types and establish clear fluid contacts. In such situations, real-time fluid sampling becomes the only way to properly delineate fluid phases. This paper showcases field experiences in the F7800 reservoir of the mature Oben field development and the structured approach applied in resolving such non-uniqueness in the planning and positioning of crestal oil producers.
Though the F7800 was initially undersaturated, well performances of the most crestal producer (well shut-in due to high GOR) and very sparse historical reservoir pressure data indicated the presence of a secondary gas cap due to pressure depletion way below the bubble point. As the downdip wells began to water out from aquifer influx, there arose a need to explore updip development opportunities. In the first identified opportunity, existing cased hole saturation logs acquired in an offset well indicated gas at the same level of the planned new development target interval. This interpretation threatened to erase the opportunity for further oil development.
In another structurally higher development opportunity, a time-lapse C-O log (taken three years apart) in the same well indicated fluid depletion down to residual oil saturation despite the fact that the perforation had been squeezed off for close to 20 years. Besides the interval was the most crestal in the structure and other downdip wells were producing dry oil. In both cases, the cased hole saturation log was at variance with the well established reservoir structure and the performance of development wells and inferred significantly less reserves. Consequently, reservoir pressures and fluid sampling/analyses were necessary to establish fluid types and contacts. The result was a 45ft upwards shift in the previously estimated fluid contact which allowed the placement of two updip development wells with a total net oil production in excess of 1500 bopd from the two updip developments. This paper will highlight the application of real-time fluid sampling technologies by a Niger Delta Operator to safeguard overall project value.
Alkali/Surfactant/Polymer Flooding Using Gum Arabic; A Comparative Analysis
Authors: Onuoha S. O. , Olafuyi O. A. 
Published: July 2013

Abstract
ASP flooding has been found to be one of the major EOR methods of successfully recovering light and medium oil left in the reservoir after primary and secondary oil recovery.
The objective of this study is to evaluate and compare the displacement efficiencies of two Alkali/Surfactant/Polymer slugs formulated with two different surfactants: an anionic and a non-ionic surfactant named Lauryl sulphate (Sodium Dodecyl sulphate, SDS) and Tween 80 (Polysorbate 80), respectively. The alkali employed was caustic soda (Sodium Hydroxide), and the polymer used here was Gum Arabic. Gum Arabic is an organic adhesive gotten from the hardened sap of the Acacia Senegal and Acacia Seyal trees, having similar molecular structure and chemical characteristics with Xanthan Gum, which is a widely used polymer for enhanced oil recovery. Gum Arabic is commercially available in Nigeria. Results from this study will prove the efficacy of Gum Arabic for use in the Nigerian oil and gas industry.
In this study, the chemicals were combined in the same composition and concentration to recover trapped oil after conventional water flooding. This was done by linearly flooding a horizontal core holder loaded with glass beads. The results from these experiments show that Lauryl sulphate and Tween 80 are both good candidates for enhanced oil recovery, with incremental recoveries of 36% and 15%, and displacement efficiencies of 90.2% and 77.9% respectively. This paper also covers laboratory and facility design requirements for implementing an ASP project.
Development of Heavy Oil Reservoirs: A Case Study of a Low API° Reservoir Offshore, Nigeria
Authors: Eremiokhale Obehi , Zeito George , Orioha Herbert 
Published: July 2013

Abstract
Heavy oil makes up approximately 15 percent of the world's remaining oil reserves. It presents opportunities that could be commercially viable but often rejected because of the inherent challenges of producing them, especially in offshore environments. These challenges include flow assurance, produced water separation and treatment and additional heat and power requirements. The common occurrence of low API reservoirs at relatively shallow depths can lower drilling and completions costs but can also increase production and transport costs and limit marketing options.
This paper describes the commercially successful production of a heavy oil reservoir offshore Niger-Delta. The field was discovered in 1968 and an appraisal well was drilled in 1970. At that time, the accumulations were deemed to be too small to develop. Forty years later the economics of oil production had changed and additional appraisal wells were drilled. Modern logs, core and MDT samples were taken. Three of the five reservoirs contained heavy oil. Reservoir simulations established initial estimates of recovery for each reservoir encountered and IPM models established inflow-outflow relationships. For the heavy oil reservoirs, the IPM showed that artificial lift would be required to produce the oil. This was confirmed by failed attempts to naturally flow an appraisal well that tested the best of the heavy oil reservoirs. The decision was taken to drill a horizontal pilot producer completed with a downhole ESP. The pilot producer was successful and several development wells were subsequently drilled in that reservoir and completed with ESP and gas lift capability.
This paper further showcases how the economics of producing a heavy oil reservoir was reversed by comingling with lighter crude and managing the challenges of crude compatibilities, produced water separation and marketing of the crude blend.
Estimating Reservoir Parameters Using Thermal Transient Testing (TDS Technique)
Authors: Nyame Michael , Dankwa Ohenewaa K. 
Published: July 2013

Abstract
In the estimation of most reservoir parameters in well test, the reservoir is assumed to be isothermal which is practically not true due to the fact that there are heat sources from friction in the wellbore, work done by the drill bit and as well as thermal recovery. Although, this temperature change is small, it can serve other beneficial purposes in the reservoir and the wellbore. The research work used the small change in temperature to estimate reservoir parameters like permeability and skin factor. This research work brought out equations to be used in the estimation these reservoir parameters and the applied to field data. This research work is applicable in reservoirs where steam flooding and in situ combustion processes are used as the enhanced oil recovery methods.
These result obtained for permeability was practically the same as the true reservoir permeability from field data although the same could not be said about the skin factor since that of the estimated and true value were quite different. This makes thermal transient testing a good substitute for the estimation of reservoir permeability. The same could not be said about the skin factor since it affect the pressure drop not temperature change.
This research work brought out the idea that thermal transient testing can be used as a tool for estimating some reservoir parameters as well as verification for estimated reservoir parameters using other well test methods.
Application of Neural Network Workflow to Facies Modeling in Turbidite Reservoirs, Offshore Nigeria
Authors: Njoku Chukwueke , Horst Peter , Akinsanmi Olatunji 
Published: July 2013

Abstract
Three dimensional static reservoir modeling is a key aspect of geoscience workflows underpinning development of petroleum reservoirs. It helps accurately characterize reservoirs, plan appraisal and development wells, and achieve high-level Well and Reservoir Management (WRM) over the production life.
Facies modeling is a critical step in the static modeling workflow because it allows us model how rock types are distributed in the reservoir and whichis the basis for modeling petrophysical property ranges associated with each facies type. The object-based approach to facies modeling has been well established within the oil and gas industry over the last ten years, however, recent efforts have been made to model reservoir facies using neural networks.
This paper reports on the application of the neural network approach to facies modeling as part of the static modeling workflow for several turbidite reservoirs in an offshore Nigeria oil field. The key input data applied to delineate and model the facies were cores, well logs, and seismic.
The authors consider this modeling approach to be successful and recommend it for modeling deep water facies with better thin-bed placement, high repeatability, and a shorter turn-around time.