bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overpressure Analysis in HPHT Environments: Lessons Learned from the Central North Sea
Authors: Nwozor Kingsley 
Published: July 2017

Abstract
The uncertainties of overpressure estimation are among the major challenges to the development of deep and hot reservoirs in many sedimentary basins especially with regards to drilling safety and well economics. However, because of the anticipated huge economic benefits of HPHT geological environments, stakeholders in the oil and gas industry consistently seek to have a good understanding of subsurface pressure systems in order to promote safe and sustainable investments therein. Accordingly, information is required to improve the regional knowledge of geopressures and for the calibration of functions aimed at optimising pre-drill pore pressure estimates for future wells. The Central North Sea, with its vast number of HPHT wells, pressure data, drilling information and documented operational experiences in exploration, drilling, development and production activities stands in a good stead as a "geopressure laboratory" for the fine-tuning of pore pressure prediction concepts, improvement of current geopressure practices and ultimately guide investment and operational decisions in the unexplored areas of the basin itself and elsewhere as geological realities could permit. For this reason, this study utilised downhole pressure-related data and wireline logs to evaluate the pressure regimes in the Central North Sea. The approach involved the quantification of overpressures using standard pore pressure prediction methods that make use of the density and velocity logs of mudstones. The results show that the estimated pore pressure profiles are consistent with measured pressure data in the Cenozoic formations, which makes it reasonable to assume that disequilibrium compaction is the cause of overpressure in this shallow section of the wells. Going deeper into the wells, within the sub-Chalk section, typical calibration parameters from log data could not be used to achieve reliable estimates of overpressures as was the case in the Cenozoic section. Remarkably, while it is possible to adjust the Eaton exponents in order to match estimates with measured data, a wide range of exponent values of between 4.0 and 7.0 is however required. The implication is that there is no systematic variation of the Eaton exponents with the amount of overpressure or depth of burial of the sub-Chalk strata.
Experimental Study of the Possible use of Locally Derived Plantain Peelings and Rice Husk as Additives for Oil Based Mud at High Temperature - High Pressure Conditions
Authors: Seteyeobot Ifeanyi , Uma Joshua A. , Enaworu Efeoghene 
Published: July 2017

Abstract
Drilling in HT/HP wells has adverse effects on drilling fluids. At high temperatures and pressures, the chemical additives used in drilling fluid formulations experience thermal degradation above 107°C (225°F) leading to strong variations (reduction) in rheological and filtration characteristics. Locally derived Rice-Husk and grounded Plantain peels were used to improve the rheology and filtration properties of back-loaded oil based mud at HT/HP behavior, and the results were compared to industrial additives like Sodium Carbooxymethylcellulosics (CMC), Polyanionic Cellulosics (PAC), and Sodium Polyacrylates (SPA). This research was centered on the use of three oil-based mud samples from a particular field in the Niger Delta basin. The samples included; a reconditioned mud, a freshly prepared mud (both with standard industry additives), and a back-loaded mud respectively. Seven [7] different mud property tests were carried out on the samples to determine their current state. After that, the back-loaded mud was upgraded with the locally derived additives and it's rheological and filtration properties were observed and compared to the results of the first two samples. The effects of high temperature and high pressure on the stability of the locally-derived additives were also observed. This was paramount because the chemical additives underwent thermal degradation at these conditions. The most significant finding is that the locally derived additives worked at the same level or probably better than the industrial additives.
The novelty of this research was to evaluate the potential of locally derived additives for improvement of mud rheology and filtration in comparison with industrial additives. Also, a reduction in the cost of purchasing foreign viscosifiers and filtration control additives by patronizing locally derived additives hence reducing the overall cost of a mud program. Lastly to make sure that wastes like rice husks and plantain peelings are recycled by usage in drilling mud formulations so as to prevent environmental problems such as heaping of refuse on the streets.
A Fit for Purpose Probabilistic Forecasting Tool PFT for Business Planning
Authors: Olayomi A. J. , Jaja A. J. , Adegboye P. S 
Published: July 2017

Abstract
The need for reliable and efficient production forecasts for business planning cannot be overemphasized. Production Forecasts are the underlining basis on which many business decisions are made. They also serve as main input into economics and decision analysis and are used for project selection. Until recently many organizations tend to rely on deterministic forecasting methods with inherent pitfalls since they don't include uncertainties in the estimates. While there are existing methods such as reservoir simulation for generating probabilistic forecasts for oil and gas, those methods are either expensive or take too long to deliver or a combination of both. The substantial investment in time and capital make these tools less available for making day to day decisions and preparing annual business plans to identify targets for the upcoming year.
The Probabilistic Forecasting Tool (PFT) was developed as a cost effective and user-friendly tool for generating reliable probabilistic production forecasts for oil, gas and water. It enables oil and gas companies to estimate a range of production forecasts using several input parameters and to evaluate the impact of each of the input parameters on the forecasted production. This tool has also found wide application in preparing monthly production outlook which might be too granular and resource-inefficient for full-blown simulation modelling.
The PFT was developed in Microsoft Excel with a built-in decline engine and incorporates a wide variety of inputs such as peak production rate, decline rate, workovers, planned/unplanned downtime, new drills, rig schedule etc. on which sensitivity analysis could be conducted. Probabilistically combining the low, middle, and high estimates of the input parameters, the PFT uses monte-Carlo simulations and Excel macro automations to generate uncertainty ranges around the input parameters. The tool then generates a cumulative probability density function of the profiles from which the forecasts at different percentiles could be evaluated
This paper will describe the probabilistic Production Forecasting Tool (PFT), its application for short term oil, gas and water forecast using decline curve analysis engine (DCA) as its foundation. It will describe the workflow for the integration of different assumptions on projects, planned downtime and unplanned downtime and show a few case histories. The application of this tool has helped in reducing man-hours required to use complex reservoir engineering forecasting tool for the same purpose. This tool has shown reliability in the production forecast numbers compared to actual production data in over eight years of its application.
Estimation of Oil-Rim Thickness with Analogue Data in the Absence of Definite Fluid Contacts: A Case study from Onshore Niger Delta
Authors: Fouzdar Amit , Kilic Cem , Das Anindya 
Published: July 2017

Abstract
One of the major challenges in field development is to estimate the possible oil-rim thickness, when only known contact is Gas-Down-To (GDT) or Oil-Down-To (ODT), and where seismic analysis cannot resolve the uncertainty. A reliable, repeatable, and practical technique to estimate the ranges of possible oil-rim thickness with the regional analogue would allow for making development decisions, as well as meeting the local regulatory requirements. An analog database with numerous proven hydrocarbon (gas and oil) column heights provides a trend for "gas-to-oil column ratio" by depth, which can be used for predicting possible oil-rim thickness at specific reservoirs with the contact uncertainty. For all the analog reservoirs, fluid thicknesses have been tabulated and a "gas-to-oil column ratio" has been calculated. A simple plot between the "gas- to-oil column ratio" and reservoir depth reveals a certain trend of increasing "gas- to-oil column ratio" by depth. In addition, database also provides a cumulative distribution of regional column heights, which could be used to constrain the maximum estimated hydrocarbon column thicknesses. The trend of increasing "gas-to-oil column ratio" by depth indicates that gas-columns gets much bigger compare to oil-columns as the reservoir depth increasing. With given depth information and estimated "gas-to-oil column ratio" from the database, it is possible to estimate possible range of oil-rim thickness. By investigating the scatter in the trend, it is also possible to estimate a range of "gas- to-oil column ratios". With the help of this methodology, in absence of any definite fluid contact, it is possible to estimate a range of oil-rim thicknesses, which has an impact on field development scenarios; i.e. "gas-only", "oil-then-gas", or "concurrent oil-and-gas" development options. In addition, it could also help field development plan to meet the regulatory requirements; i.e. providing a strong case not to develop or appraise the oil rim.
Localized Pitting Corrosion of Super Duplex Stainless Steel in a Sea Water Application: Practical Case of When Chlorination was Not to Blame
Authors: Alum Moses A. 
Published: July 2017

Abstract
The Fire Water Pump (FWP) Columns were being dismantled and removed on August 3rd 2015 for the installation of anodes originally not installed barely one year after plant start-up in December 2014, in a re-developed Brown Field offshore Nigeria.
Given that the material used in the manufacture of the columns were made of A890 Grade 6A (Super Duplex Stainless steel) materials, the unexpected was observed, "Severe localized pitting corrosion" from the internal on one of the seawater submerged section of the columns (column 9), and on further examination of the pitting, two (2) pin holes were found. This discovery led to stoppage of the activity, and to dismantle and remove already coupled columns 11 and 10 (which had the anode already clamped on it) for additional inspection.
Visual Inspection and thickness measurements were carried out on all the eleven (11) columns of the FWP on the 4th August, 2015, and similar observations were made. It is well known and demonstrated that the performance of Super Duplex stainless Steel in Seawater conditions has generally been excellent with few problems, so why did we have these pitting corrosions less than one year after the Pumps were put in service? The usual culprit, Chlorine, known to initiate Chromium-oxide breaks at the passive film of stainless steel material thereby increasing their susceptibility to localized pitting and crevice attack was initially suspected. However, practical examples and applications show that Super Duplex Stainless steel can still be resistant to both pitting and crevice corrosion even in extreme corrosive conditions of excess chlorine dosing. So what went wrong? Further investigations were carried out to answer the posers.
This paper will tell us what went wrong and why. It is a practical case study of where even though sea water chlorination was present, yet it wasn't the dominant factor that led to severe localized pitting corrosion and holes in Super Duplex stainless steel materials.
Multi-Tank Material Balance Analysis in Heterogeneous Oil Reservoirs
Authors: Molokwu V. C. , Onyekonwu M. O. 
Published: July 2017

Abstract
This paper presents detailed theories and method of determining fault transmissibility and production history matching using the multi-tank material balance. This approach uses a two-step optimization process whose algorithm can be written as macros in spreadsheets. The upper-level (outer) stage optimizes the transmissibility and hydrocarbon initially-in-place while the lower-level (inner stage) optimizes the pressure of the support tank at each time step. This approach is validated using numerical simulation. This approach will be highly beneficial in effective reservoir management where little or no 3D seismic exists and for cases of sparse production data.
Optimizing Reservoir Ultimate Recovery and Reserves Replacement via Efficient Opportunity Generation
Authors: Dennar Linda , Emelle Chima , Essien Uwem , Suleiman Ahmed 
Published: July 2017

Abstract
Having a long-term plan to maximize economic recovery of hydrocarbons whilst delivering reserves today is at the core of sustainable development in EP Business Plan Priorities (especially reserves replacement ratio and growing the resource base).A typical hydrocarbon maturation funnel, which is a graphical representation of existing projects underpinning the maturation of volumes gives insight into the maturity of the projects, sustainability of production, reserves replacement over time and availability of maturation options. At reservoir or field level they provide information on the ultimate recovery that is currently expected and highlight which recoverable volumes are not yet underpinned by projects.
Continuous refreshing of the maturation funnel can never be overemphasized and the success of this refresh is determined by the quality and number of opportunities generated over time that gives an accurate perspective of the full life cycle recovery expected from the reservoir, rolled up to the field level. The objective of an effective opportunity generation process is to clearly identify new projects and provide answers to certain pertinent questions like; a) are all the volumes in this funnel supported by projects? b) what reserves replacement does the funnel yield in the next 5 years? c) what ultimate recovery does the funnel yield? d) What type of recovery processes will be employed now and in the future?
Field A was used as a case study to test the efficiency and impact of this process with special reference to production sustenance and life cycle recovery optimization. A Portfolio Review of fields in the asset was held and this prioritized Field A among the top opportunities for further development. Seventy percent of oil volumes in the asset reside in 11 top fields and field A was a part of this category. The field has an expectation STOIIP of 1602.2 MMstb with ultimate recovery of 520.9 MMstb (RF 33%). The cumulative production from the field as estimated was 300 MMstb and expectation reserves was 89.5 MMstb, meaning an opportunity gap of 131 MMstb remains for which projects could be identified.
The field was selected for a Technical Review exercise due to its large STOIIP, low UR, depletion rate and decline in production. The review outcome identified gaps in data availability and volumes. A total of 40 opportunities were generated to mature70.1 MMbbl and as such optimising the life cycle ultimate recovery. This paper will highlight the process of efficient opportunity generation, its gains and effect on life cycle recovery using field A as a case study.
A Model for the Prediction of Hydrate Growth Initiation Point by Determining Quasi Liquid Layer Temperature
Authors: Oluwatoyin Akinsete O. , Obode Elizabeth I. , Ibadan Ibadan , Isehunwa Sunday O. 
Published: July 2017

Abstract
Hydrates constitute a major flow assurance challenge in the transportation of unprocessed gas through flowlines. Its undesirability stems from the fact that these solids reduce pipe diameter open to gas flow, challenge pipeline integrity, possibly leading to burst pipe – and increasing costs. Hydrates undergo four stages of maturation – entrainment, growth, agglomeration and plugging – and do not usually constitute a flow assurance challenge until agglomeration. These challenges are even more pronounced in the presence of gas-condensate in the flowline.
This paper proposes a model to predict the point in the flowline where hydrates start to form in the presence of gas-condensate. This is done by predicting the temperature at which quasi liquid layer starts to form on the hydrate seed. Quasi liquid layer refers to a film of pure water that forms around the hydrate seeds at a particular temperature drop within the system. When two seeds with this layer come together, they become joined together via capillary bridging – and the resulting crystal is bigger than the component seeds – thus leading to growth.
The developed analytical model relates mass of hydrate, length of the flowline, time taken for fluid flow in the system, the percentage of hydrate in the fluid composition, density of the hydrate, change in enthalpy and the velocity at which hydrate is flowing in the system to the temperature at which hydrates would start growing – that is the quasi liquid layer temperature.
The developed model was validated with field data, and the model was in agreement with field observations.
Harnessing Upstream Gas Resources for Power Generation in Nigeria: Issues, Strategies & Economics
Authors: Green Ovunda , Adeogun Oyebimpe , iledare Omowumi 
Published: July 2017

Abstract
Nigerian gas industry is gradually developing into an important sector of the nation's energy economy. Proved natural gas reserves is known to be substantially larger than oil potential in energy terms and it is estimated to be about 180Tcf.
Globally, natural gas has continued to displace other forms of fossil fuels for power generation due to its abundance, low carbon content and efficient technology. Gas, therefore presents the most viable option to bridge the existing gap between power generation capacity and demand in Nigeria. Despite Nigerian's huge potential in terms of gas resources and market, the gas sector is still plagued with perennial underdevelopment, principally caused by lack of clear fiscal regulatory framework and non market based gas pricing.
This paper, analyzes the economics of harnessing upstream natural gas for power generation using discounted cash flow model. Inputs for the model include a proposed PSC fiscal regime for offshore gas development; benchmark gas price for the power sector; cost estimates, production profile; discount and inflation rates. The estimated result in terms of the profitability indicator (NPV & IRR) and the discounted host government take (DHGT) shows the impact of the fiscal regime and gas price on profitability of upstream gas investment. IRR and NPV shows investment to be profitable at a base case gas price of $2.5/mcf. Further analysis carried out with respect to low, medium and high cost gas fields for associated and non-associated gas reveals that low and medium costs associated gas field and low cost non associated gas fields are profitable at a gas price of $2.5/mcf. Sensitivity analysis showed that high cost associated and non-associated gas fields are profitable at a gas price of $4.5/mcf. Stochastic analysis was also carried out to capture uncertainties associated with some variables used as input in the initial cash flow.
Prediction of Sand Production from Oil and Gas Reservoirs in the Niger Delta Using Support Vector Machines SVMs: A Binary Classification Approach
Authors: Olatunji Oladipo O. , Micheal Obolo 
Published: July 2017

Abstract
Sand production is one of the critical research subjects in the petroleum industry. In the oil and gas industry, the production of sand particles associated with the reservoir hydrocarbons has become one of the most common problems a well may experience during reservoir lifetime.
Sand production occurs in many fields across the world. This is easily seen in wells in the Niger Delta, Gulf of Mexico, Oman, Canada, Venezuela, Indonesia, Egypt, Trinidad and myriads of other places prolific to sanding. Managing sand production and ultimately its control in the oil and gas industry has been more or less a recurring problem. To fully understand the nature of sanding in an ingenuous way for sand control strategy, it is necessary to predict the conditions at which sanding occurs. Because so much have not been done in the implementation of the support vector machines for the prediction of the sanding onset in petroleum reservoirs, we are, for the first time, applying a robust approach, a binary classification problem approach for the prediction of sanding onset in petroleum reservoirs in the Niger Delta Region. By and Large, for the first time, the support vector machines (SVMs) classification approach, is used to identify whether sand will be produced or not in a hydrocarbon reservoir. The model presented in this paper takes into account different parameters (rock, fluid, geotechnical and other data) that may play a role in sanding. The performance of the proposed SVM model is verified using field data.
It is shown that the developed model can accurately predict the sand production in actual field conditions. The results of this study indicate that the implementation of SVM methodology can effectively help engineers to make a proactive sand control plan with insignificant impairment to hydrocarbon production from subsurface reservoirs.
Optimization Study on Inflow Control Devices for Horizontal Wells in Thin Oil Column Reservoirs: A Case Study of a Well in Niger Delta
Authors: Archibong Charles , Erhiaganoma Ese , Ikehi Emmanuel 
Published: July 2017

Abstract
Horizontal wells have been used to maximize recovery from thin pay reservoirs but this does not eliminate early water/gas breakthrough problem due to the presence of a non-uniform inflow along the completion. This uneven inflow is as a result of non-uniform pressure losses along the completion and instance reservoir heterogeneities. The non-uniform pressure losses causes higher flow rate and early break through from the heel sections than from the toe and the occasional presence of permeability variations creates zonal variations in water and/or gas encroachment.
Recent research efforts have led to the successful application of smart completions (Inflow Control Devices [ICDs] / Inflow Control Valves [ICVs]) to suppress the non-uniform inflow. The selection of optimal ICD configurations for such smart wells is normally obtained from a trial and error simulation with different configurations. A more recent study proposed a model for calculating optimal ICD strengths without flow simulations. The earlier solution with trial and error simulation is time consuming and the later solution with no flow simulation will not capture the influence of reservoir heterogeneities.
This paper presents the application of a new approach to ICD optimization in a horizontal well located offshore Niger Delta. The approach involves the development of a diagnostic algorithm which utilize results from a basecase simulation with an openhole horizontal well in order to determine the optimal ICD configuration for the well. The configuration parameters specified as optimization control variables in the algorithm include ICD strengths, the total number of ICDs in the wellbore and the valves density per ICD's compartment. A comparison of recoveries is made between an open-hole completion case, identical ICDs’ configurations case and the optimized ICDs case.
The case study is carried out with autonomous inflow control devices (AICDs) but the optimization's control variables are independent of the choice of ICD.