bluuebunny/crossref_metadata_2025_split huggingface dataset:
Indigenous Vendor Qualification for Thermal Insulation Coating for Deepwater Pipelines
Authors: Chukwujindu Ifeoma , Olanruwaju Olayera , Andrews Kevin , Akpovir Matthew 
Published: August 2012

Abstract
The purpose of this paper is to discuss capacity and capability verification exercise conducted for qualifying a Nigerian-based coating vendor for application of anti-corrosion coating (three layer polypropylene) and insulation coating (five layer polypropylene) on line pipes for risers and flowlines to be installed offshore (deepwater) Nigeria.
The search for new oil and gas discoveries and increasing production volumes has driven oil companies to deeper ocean depths posing significant and unique challenges. A major challenge faced in deepwater fields is producing high pressure and high temperature reserves with significant subsea infrastructures and tens of kilometers of tie-backs to production facilities. This need to operate at greater depths with longer subsea tiebacks requires a high reliability method to address flowline and riser corrosion and insulation (hydrate/wax formation) requirements. The use of engineered pipeline coatings has been identified as the "first line of defense" in addressing these challenges, and a cost effective and reliable mitigating strategy.
With a possible loss of production or shut-in, the cost of conducting periodic inspections, maintenance and repair work offshore deepwater is enormous such that the reliability of the facilities has a positive impact on the operating expenditure; the right choice of coatings, to prevent external corrosion and reduce the rate of heat transfer from the production fluid to the environment, would help improve the reliability of the risers and flowlines. Industry-wide experience varies in the use of these coatings, with some operators experiencing some significant failures. To avoid these failures, engaging a qualified coating vendor, with the appropriate skill set, knowledge, and experien e is critical.
In an effort to meet industry standards and ExxonMobil requirements, Esso Exploration and Production Nigeria Limited (EEPNL), with participation of the Nigerian National Petroleum Corporation (NNPC) and Nigeria Content Development Monitoring Board (NCDMB) identified a Nigerian coating company, Pipe Coaters Nigeria Limited PCN), and conducted a coating qualification exercise for application of anti-corrosion (three layer polypropylene) and insulation (five layer polypropylene) coatings intended for use on Erha North Phase 2 risers and flowlines.
Application of Portable Gas-to-Liquid (GTL) Plant in the Niger Delta Fields
Authors: Abanum A M. , Onyekonwu M. O. 
Published: August 2012

Abstract
Natural gas is one of the earth's natural resources and in Nigeria, it is abundant. When converted to liquids using the Gas-to-Liquid (GTL) plant, super clean diesel fuel (AGO), naphtha, kerosene and gasoline are produced. With the expected rise in demand for diesel fuel, Gas-To-Liquid, GTL provides an option with qualities that can enable significant reductions in emissions and utilization of natural gas being flared. The objective of this paper is to see how the Portable GTL Plant Technology is applicable in the Niger Delta fields, as compared to the conventional technology of crude oil refining. It was believed that the GTL plant would never be economic if it is not a massive project and oil prices must remain high, but this axiom has being challenged and considered to be untrue with the introduction of Micro-GTL plants and fuel formers. A careful review was carried out to study and apply developments in GTL technological innovations, available reports and data to show that portable GTL plants are economically viable. With GTL plants annex to the existing flow stations and gas plants, production of liquid fuels for company's own use and supply to the local market would be guaranteed. This will also tackle the devastating effects of natural gas flaring. The cost of GTL diesel fuel is comparatively lower than the conventional diesel as presented in the cost benefit analysis of the subject. This paper therefore, provides the fundamental knowledge of portable GTL plant technology economics in the Niger-Delta fields for natural gas optimisation, curbing the effects of gas flaring and provision of cleaner liquid fuels.
Pressure Testing of Horizontal Wells in Anisotropic Composite Reservoirs – A 3D Semi-analytical Approach
Authors: Ezulike D. O , Igbokoyi A. O 
Published: August 2012

Abstract
This paper illustrates how composite reservoirs are characterized using Tiab's direct synthesis (TDS) and curve matching techniques; providing insight into the three dimensional nature of associated fluid flow.
For the first time using transform methods, a general customizable three dimensional point source semi-analytical solution for drawdown response in composite clastic systems separated by a leaky fault is developed. This solution is converted to line source for horizontal wells by integrating along the producing well length while treating the leaky fault as a thin finite conductivity fracture separating two reservoirs with different rock properties. An arbitrary well orientation to principal permeability direction is adopted to obtain a general solution in an anisotropic system and this solution is achieved using a simple computer program which can generate type curves in a computationally cheap and effective manner. Sensitivity analysis conducted on the pressure drawdown signature with respect to areal permeability anisotropy, orientation angle, reservoir dimensions, dimensionless fault conductivity and mobility ratios in composite reservoirs reveals that the drawdown response is a convoluted function of reservoir properties from both compartments and the separating semi-permeable medium.
Three field examples from reservoirs in the Niger Delta used to validate this semi-analytical model yields comparable result with good type curve match. The TDS of reservoir parameters from the resulting equation is examined. From the resulting type curves, it is observed that there exists a limiting fault conductivity, compartment-permeability contrast and well-fault distance among other reservoir parameters that could register on the drawdown response signature.
The result of this work is attractive where sand juxtapositions separated by leaky faults in the reservoir is suspected to allow flow from adjacent fields, where vertical permeability plays a major role in depletion, where the reservoir compartments are very heterogeneous and anisotropic, and where sensitivity analysis is to be performed on any reservoir parameter in curve matching analysis.
Optimizing Waterflooding Schemes and Completion Decisions in Deepwater environments using Formation Pressure While Drilling (FPWD): A Bonga Field Application
Authors: Adoghe Leo , Effiom Oghogho , Bakare Olatunji , Nkanga Akanimoh , Liu Forrest , Okoroafor Rita 
Published: August 2012

Abstract
A key uncertainty associated with Deepwater Turbidites is the reservoir continuity or connectivity, which has been observed in Bonga field. The Bonga field is one of the premier deepwater fields in Nigeria, discovered in 1996 and operated by Shell Nigeria Exploration and Production Company (SNEPCo) since 2005. With several wells under production, water flooding is employed for reservoir pressure management, aiding optimized recovery. Reservoir connectivity uncertainty is a typical issue with these deepwater turbidites, with adequate planning required to ensure risks associated with reservoir connectivity are accounted for and addressed.
Although several producer and injector well-pairs have been drilled, data collected and analyzed, connectivity uncertainties still remain high in the field. One key source of information for understanding connectivity issues are formation pressure tests taken periodically (before and during the productive life of these reservoirs).
In Deepwater Nigeria, these formation pressures are typically taken while drilling (Formation Pressure tests while drilling - FPWD), and augmented with data from down hole pressure gauges installed in many of the wells. This pressure data is acquired and analyzed to understand the reservoir pressure depletion trend, waterflood patterns and efficiency, as well as identify sand compartments within the reservoir.
This paper discusses the use of formation pressure while drilling data in a new Bonga injector. The data was used to confirm connectivity with a paired updip oil producer, which was critical in making real-time decisions on completing the well, reducing drilling and completion risk, as wells as reducing the rig cost associated with the entire well operations.
Power Law Concept on Darcy's Flow Model: A New Approach for Analysing Gas/Condensate Well Deliverability
Authors: Livinus A. , Obah B. 
Published: August 2012

Abstract
The productivity of gas and oil well plays an important role in gas and oil field development, particularly gas condensate well that is characterised by severe loss of well deliverability due to liquid drop out below the dew point, and for establishing field proration schedules and setting maximum allowable production rates for individual wells by regulatory agencies. Houpeurt equation and Rawlins-Schellhardt equation are the most widely used gas deliverability equations by engineers. Although the Houpeurt equation has a theoretical basis and is rigorously correct, the equation assumes that Darcy's law is still valid under high velocity of gas flow and that an additional term must be added to account for the increased pressure drop. The Rawlins-Schellhardt equation still continues to be used by the natural gas industry, however it was empirically formulated and the deliverability plot is traditionally reversed in order to estimate the deliverability exponent.
In this work, a new gas/condensate well deliverability equation under pseudo-steady-state condition is developed using the power law concept on Darcy's model of flow: this is suitable in view of the fact that Darcy's law breaks down under conditions of high velocity flow which is proven to exist in gas/condensate wells. Thus this concept vehemently account for the non-linearity between gas flow rate and potential gradient due to inertial effects in the porous media. The formulation procedures are detailed. An illustrative example in which the new equation is applied to field data is included. Results comparison between the new equation and the traditional dry gas equations by Houpeurt, and Rawlins-Schellhardt is made to illustrate its capabilities, and the correlation between the three methods is shown.
The new approach will provide a single and useful tool for estimating gas/condensate well productivity.
Innovative Wireline Logging Acquisition Coupled with Advanced Data Processing and Integration Allows Accurate Identification of Pay and Formation Fluids in Complex Reservoirs
Authors: Martey Amarquaye , Otevwemerhuere Joseph , Schils Jeroen , Cavalleri Chiara , De Santo Ilaria 
Published: August 2012

Abstract
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.
Reducing Field Development Risk in Marginal Assets through Probabilistic Quantification of Uncertainties in Estimated Production Forecast - Tsekelewu Case Study
Authors: Obeta Chukwudi. C. , Ugonoh Mohammed. S. , Ajayi Olajumoke. C. , Sijpesteijn Casper Kaars 
Published: August 2012

Abstract
Tsekelewu field North of Niger Delta consists of twin structural culminations and two well penetrations. Because it is poorly appraised, fluid distribution within the structure is not well defined, with almost all encountered hydrocarbons found in Oil-Up-To configurations. The limited available PVT data is of questionable quality, and there is no core and SCAL data to calibrate the evaluated petrophysical parameters. Moreover, the lateral extent of Opuama channel which eroded the Eastern limit of the field is not well defined by seismic, thereby allowing part of the trapping configurations to be only inferred. These aforementioned data gaps introduce significant uncertainties in fluid levels, lateral reservoir and structural continuity, fluid properties and distribution, geologic and petrophysical properties, presence and size of available aquifer for the Tsekelewu marginal field. Due to the nature of marginal field development, often key development decisions are based on a single deterministic scenario of volumetric estimate and production forecast. This poses additional risk to marginal field development. In order to provide a robust framework that adequately frames the spectrum of subsurface uncertainty, we applied Experimental Design methodology using a proxy model to probabilistically evaluate resource volume, rank and risk opportunities, tested various development concepts and generate production forecast for the Tsekelewu Field. This paper emphasizes the limitations of a single realization and makes a case for adopting a model that reduces risks associated with investment decisions in marginal fields.
The significant difference between deterministic STOIIP estimate and forecast, and the P50 realizations from model probability density function highlights the value in investigating all possible outcomes. This study provides the basis for the forward looking strategy for Tsekelewu Field Development.
Modeling Miscible Gas Injection in the Agbami Field
Authors: Matthew E. Rhodes , Odusote Femi , Hanschitz Martin , Aigbe Chris 
Published: August 2012

Abstract
In this study, the current reservoir management and prediction tools used by the Agbami asset to simulate the field's miscible gas and water injection strategy were validated by comparing the forecasts with a compositional based simulation model. The current development plan for the field calls for crestal reinjection of produced gas and water injection along the flanks. The current workflow to generate the production forecasts uses the profiles from a black oil, miscible simulation model. This model, built with a commercial black oil simulator, utilizes the Todd-Longstaff model (Todd & Longstaff, 1972) to simulate the miscible gas injection process. To provide further confidence in the modeling approach, an alternate simulation technology was selected. Using this methodology the PVT behavior and resultant miscibility of the reservoir and injection fluids were modeled explicitly with an equation of state (EOS). To provide an appropriate characterization of the reservoir fluid, an EOS model which provided a reasonable representation of the subsurface variation of fluid properties was built and compared to the current black oil fluid model. To convert the simulation model to an EOS based compositional model the black oil format was rewritten in the chosen compositional format ensuring consistency as far as possible. The extensive history matching work on the black oil model was then leveraged to accelerate the matching of the compositional model and then forward predictions were run on the base case to evaluate the effect of the new PVT characterization on the potential recovery of the field. This was then compared to the current black oil model to determine the drivers behind the differences observed and the potential reservoir management effects which may occur. On the field scale it was found that there was less than 0.2% difference in total cumulative oil production with the EOS modeling approach providing insight into the changes in oil properties as the miscible gas was injected over the life of the reservoir.
Sanding in Oil Well Reservoir Completions
Authors: Vincent O. Nwabueze , Abiola S. Onikoyi , Felix O. Okoro , Ajienka J. A. 
Published: August 2012

Abstract
Sand production in oil wells impairs full reservoir production capability, erodes sand face completions, down-hole tubular and surface equipment. The debilitating effects of sand production on surface production equipment are manifested in the plugging of flow lines, production manifolds and separators, leading to significant deferment in production due to downtime of facilities for sand clean out and component repair and replacement.
2000 oil wells in the Niger Delta area have been reviewed to understand the sanding tendencies of the oil well completions and establish the completion strategy and practices that have successfully reduced sand production and its impact. It is observed that over 100 Mbopd oil is locked in as a result of produced sand. A plethora of sand control mechanisms such as Internal Gravel Packs, External Gravel Packs, Stand-Alone Screens, Premium Screens and Sand Consolidation Chemicals have been installed to reduce sand production in oil wells to acceptable rates but several cases of failures have been observed reviewing the past history of the oil wells.
While several operators have developed guidelines to judge when sand control is required and how to operate the oil wells safely, there are still grey areas to be explored to understand the variation of formation consolidation indices from one Depo-Belt to another. The sand production performance of 2000 wells have been reviewed to examine whether the tendency for sanding can be attributed to oil well completion techniques or in-situ formation consolidation or a combination of both. It is also widely believed that formation burial depth can be used as a consolidation parameter to decide whether to include sand control in oil completion design or not.
This paper seeks to share the results of the review of a large population of wells located and completed in different Depo-Belts in the Niger Delta with a view to helping operators streamline their decision-making process to include or not to include sand control systems in their oil wells for efficient production performance at less deferment due to sand production and lower completion and operating cost.
Renewable Power Supply Option for Smart Fields Implementation in Oil and Gas Production Installations in the Niger Delta
Authors: Idachaba Francis , Okuns Godwin , Oluwatoyin Fasasi , Amiesimaka Tokoni , Brennan M. , Hawrylak R 
Published: August 2012

Abstract
Power supply at any level in the Nigerian Niger Delta is a challenge due to the high rate of vandalism, the lack of infrastructure and the dependence of the Smartfields implementation on the availability of highly reliable power supply systems. For power supply systems to meet the availability and reliability criteria for Smartfields operations, the systems must be vandal proof and renewable with 100% availability and minimal negative impact on the environment. This paper presents the results of field trials of a renewable power supply system suitable for the deployment of Smartfields in remote locations in the oil and gas industry. The power solution is implemented using lithium polymer batteries, explosion proof enclosures and a thermoelectric generator to create a renewable power supply solution. This solution is capable of providing power to all the well head valves and communication infrastructure of both the gas lifted and natural flowing wells with high reliability and availability and also with a very low susceptibility to vandalization and very negligible negative impact on the environment.
Trends on Competitive Machine/Product Design
Authors: Mahmud J. O. , Ismail M.S. Mohd , Taib J. Mohd 
Published: August 2012

Abstract
In the past decade there has been increasing transformation in Design and Design activities for Machinery/Products aimed at lowering cost, space required, without reducing the efficiency of Machinery/products using the TRIZ principles. This paper focuses on the Trends of Competitive Machine/Product Design that designers need to get accustomed with if they must conform to best practices. This paper addresses these styles of transformation using the Total Design Model and TRIZ Inventive Principles: Trends of increasing degree of Trimming and the Trends of transition to the supersystem. Case studies adaptable to the Oil and Gas sector are carefully selected to support the concept generation part of the model. This work will assist equipment/product designers in recognising the product and equipment transition through the three stages of "Trends in Engineering systems and evolution". Designer practitioners in the oil and gas sectors will find the approaches in this work very useful in terms of time saving and reduced costs.
Annular Pressure Prediction During Well Control
Authors: Omosebi A. O. , Osisanya S. O. , Chukwu G. A. , Egbon F. 
Published: August 2012

Abstract
Annulus pressure rises when circulating out a gas kick because gas expansion reduces the height of mud in the annulus. Kick is the uncontrolled flow of formation fluid and occurs when primary well control is lost (i.e. hydrostatic pressure is less than the formation pressure. The inability to control the kick with the blow out preventer system leads to blowout, the worst disaster while drilling. Existing techniques used in predicting annular pressures during the control process generally assume an ideal situation where the kick enters the wellbore as a continuous slug with no slip velocity relative to the mud as it rises up the annulus.
This study presents new analytical models for predicting annular pressures during well control. The models harmonize the cases when the kick is mixed with the mud (most appropriate case) and when the kick comes in as a slug. Analytical solutions and computer programs were developed and validated using published data. Finally, sensitivity studies were conducted to determine the effect of formation permeability, kick volume, and wellbore geometry on annular pressure profiles at any depth of interest.
Results show that the "mixed" model demonstrates good prediction of the annular pressures when compared to the "continuous slug" model. Results also show that the annular pressure buildup profiles prior to stabilization are highly sensitive to formation permeability. Also, the "Mixed" model is highly sensitive to kick volume and wellbore geometry while the "Slug" model is slightly sensitive to only kick volume and wellbore geometry.