bluuebunny/crossref_metadata_2025 huggingface dataset:
Suitability of Local Demulsifier as an Emulsion Treating Agent in Oil and Gas Production
Authors: Oriji A. B , Appah Dulu
Published: August 2012

There is an increasing need to limit the use of chemical treating agents during oil and gas production and to search for safer and cost effective ones mainly due to environmental constraints. Therefore the use and performance of demulsifiers have to be improved from the application and cost as well as from the environmental issues. This means that new formulations must be less toxic and efficient compared to the general classical chemical families of demulsifiers which contain toxic molecules like phenol groups.

This paper is on the performance and the comparison of four chemical demulsifiers (local and foreign) on their demulsification of four crude oil emulsions of different asphaltene contents from different oil wells in the Niger Delta. The chemical families of these demulsifiers were screened with effective separation ability of different surfactants using classical "Bottle test". The Bottle test helped to determine the type of demulsifier that will most effectively break the emulsion of the crude samples. The basic aim of this screening was to compare and rank the efficiency of the various demulsifiers both local and foreign (V4404 of Nigeria, 92LTM174 of USA, EN/82/2 of France and DS 964 of Canada) in terms of percentage (%) volume of water that will be separated out of the samples. The results showed that the viscosity of the emulsions increased as the water content increased with an assumption that only oil and water were present. The nature of the emulsions were subject to changes, therefore no treatment method was conclusively generalized as best for every emulsion problem. Finally from the preliminary screening, the result also revealed that V4404 a local demulsifier exhibited very interesting performance and was also environmentally friendly compared to the imported ones.
Lithofacies Estimation by Multi-Resolution Graph-Based Clustering of Petrophysical Well Logs: Case Study of South Pars Gas Field of Iran
Authors: Aghchelou M. , Nabi-Bidhendi M. , Shahvar M. B.
Published: August 2012

South Pars gas field is the largest gas field of the world, located at the boundary between Iran and Qatar in the Persian Gulf in a distance of 100 kilometres from the southern shores of Iran. Its gas-in-place is estimated to be about 14.2 trillion square meters while the amount of its condensate-in-place might be around 18000 million barrels. South Pars gas field also has an oil layer containing about 6 billion barrels oil-in-place. Since South Pars field is a heterogeneous carbonate system, lithofacies characterization is the best solution for overcoming the problem of heterogeneity in determining the petrophysical properties of the reservoir rock, reservoir modeling and identifying producing zones, but coring which is the most robust method of lithofacies identification is very expensive, time consuming and is limited to few number of wells. Therefore this study is focused on determining the lithofacies of the understudy formations from available well logs. For this purpose multi-resolution graph-based clustering (MRGC) technique which is a dot-pattern recognition method based on non-parametric K-nearest neighbor and graph data representation is applied on sonic, density, neutron porosity and gamma ray well logs to define electrofacies similar to core-derived facies that are determined as twelve distinct ones. The cluster of the MRGC method is defined from model that has specific character associated with the group of lithofacies. Then, Kernel representative index is used to calculate the optimal number of clusters. Small facies groups are formed based on utilizing the neighboring index to determine a K-nearest neighbor attraction for each point. At last, final clusters are constructed by combining the small clusters which lead to identifying 12 facies of South Pars gas field from well logs by high accuracy. Method used in this study has obviated the need of extensive coring in the South pars field which caused saving large amounts of money and time.
Indigenous Vendor Qualification for Thermal Insulation Coating for Deepwater Pipelines
Authors: Chukwujindu Ifeoma , Olanruwaju Olayera , Andrews Kevin , Akpovir Matthew
Published: August 2012

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

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

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

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

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

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

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

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

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

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

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.
Splitting the Heptanes-Plus Fraction of Condensate and Volatile systems: Application of the Gamma Distribution Model
Authors: Imo-Jack Otavie O. , Uche Ifeanyi N.
Published: August 2012

Gas condensates and volatile fluids require detailed Equation-Of-State (EOS) characterization to account for compositional variations with pressure, volume and temperature changes. Proper characterization is important in determining the in-place volumes of gas condensates and volatile systems. These volumes are important in determining reserves which play an important role in driving a company's share value. The in-place volumes also drive sales contracts as well as surface equipment design. Gas condensate reservoirs also pose a serious challenge to well productivity especially below the dewpoint in tight reservoirs due to condensate banking. As this situation may lead to expensive stimulation projects, it is important to optimally define operating standards early in the life of the asset. Accurate PVT characterization of gas condensate fluid is key to defining these standards. It is therefore important to get these fluids properly characterized so as to make the right investment decisions.

EOS characterization of heptanes-plus requires extended analysis beyond the C7+ fraction. In several instances, we do not have True Boiling Point (TBP) data for these heavy components. In cases where available, experimental data still remains the most reliable source of heptanes-plus properties.

Heptanes –Plus in reservoir fluids contains hundreds of different components which are impossible to identify by chemical separation techniques. Even if it were possible to identify them, it would not be possible to measure the critical properties and other EOS parameters for fluids heavier than C20. This problem is solved practically by making approximate characterization of the heavier compounds with experimental and mathematical methods.

A molar distribution model can be used to estimate the properties of heptanes-plus. A molar distribution model is a relationship between cumulative molar quantity and some expression for Cumulative molecular weight. Different methods are used to describe molar distribution. Some methods employ a consistent separation of fractions (e.g., by SCN) thus leading to the expression of the molar fraction as a direct relationship between mole fraction and molecular weight of individual cuts. Most methods in this category assume that C7+ molecular weights decrease exponentially. A more general approach uses the three-parameter gamma probability function to describe molar distribution.

The Gamma distribution model is used in this work to study the splitting scheme of the C7+ and compare this with experimental data from extended analysis to see how they compare. If the results prove to be acceptable, then the three-parameter gamma model becomes an alternative in the absence of hard data to split heavy ends to improve their characterization.
Petrophysical Characterization of Radioactive Sands - Integrating Well Logs and Core Information: A Case Study in the Niger Delta
Authors: Chudi Obinna , Simon Roya
Published: August 2012

The gamma ray (GR) tool responds to the amount of radioactive material contained within the rocks adjacent to the borehole. These rocks emit gamma rays with enough energy to get to the detector in the tool. GR log is used for correlation, lithologic identification, and as a shaliness indicator. This is because GR have a high affinity for radioactive mineral like potassium (K40), uranium (UR) and thorium (Th), which are contained in shale and would flag off as a high radioactive count on the log. In contrast, sands are characterized by low radioactive content, giving rise to low GR count. If the sources of the sediments are near-by granitic highlands, the sands and gravel may contain zircon or may be highly arkosic (high feldspar content), with high content of K40. The question in this case is whether or not the natural gamma ray log can be used as a sand/shale or reservoir/non reservoir discriminator and how it impacts on picking reservoir tops and bases for net pay calculation.

This paper presents an example of reservoir characterization of radioactive sands from the J5000 reservoir complex of the Bemu field, Niger Delta. It discusses the methodology applied using all available data in the field to fully characterise the reservoir. On the average, radioactive sands make up part of the upper 105ft of the J5000 reservoir complex that is further subdivided into two reservoir zones, J51 and J52, separated by intra-reservoir shale. These two zones form the majority of the productive interval in nearly all the existing 49 wells, with an average porosity of 24 and 26% respectively. Average permeability values of 900 and 1800 mD based on core data-derived equation.

Net pay criteria were determined by applying a cut-off to volume of shale (Vshale), generated from a combination of neutron and density log. These methods were further compared to the conventional method of Vshale from GR. Furthermore, Saturation height modelling generated from brine-oil cap-curves was performed which served as an input in calculating in-place hydrocarbon volumes.

The results from this study shows that an in-place volume of 114 and 280 MMstb for J51and J52 was achieved using a net-to-gross of 0.79 and 0.89 based on a cut-off on Vsh generated from a combination of Neutron and Density log. In comparison a net-to-gross of 0.47 and 0.46 were estimated by applying a cut-off to Vsh from GR, thus resulting to a lower in-place volume of 70.5 and 144 MMstb for J51 and J52 reservoirs respectively.
Novel Application of QuantiMin SQP Methodology for Improved Reservoir Characterization in a Deepwater Turbidite Field Development
Authors: Arogun Olubunmi , Nwokolo Christopher
Published: August 2012

The success of any green as well as mature field development planning and execution lies in the ability to recreate the environment of deposition with the appropriate spatial and temporal facies interdependencies. This, when done with proper application of the varied suite of geotechnical software/knowhow, often leads to the creation of a finite number of high resolution and equiprobable reservoir models within a macro and micro sedimentological framework, that readily lends itself to optimized risk and uncertainty management. This becomes even more critical in deepwater turbidite systems where the impact of geologic uncertainties can significantly reduce project value and does often prevent marginal field developments in the absence of a low cost tie-in option.

This paper presents the novel application of one such technique; the QuantiMin methodology approach improves aspects of reservoir characterization and facilitates various aspects of well and reservoir management in the waterflood development of a Miocene deepwater turbidite system in the Gulf of Guinea.

The QuantiMin technique is a sequential quadratic program that solves non-linear problems by series of quadratic programming steps. When applied in this context, it assesses the mineral and fluid content around the near wellbore area, based on their unique well log responses, and returns with a finite volume distribution of mineral and fluid distribution around the wellbore, using the mineral and fluid distribution input from appraisal well cores as the calibration or control variable.

The results from QuantiMin analysis have been used in this field to:

Evaluate the potential impact of mineralogy on the performance of water injection wells. Apply understanding of mineral types around the wellbore to the design of acid stimulation recipes. Develop a framework for understanding the field scale distribution of heterogeneities by establishing the interdependencies between log-scale QuantiMin and microscopic core petrography data, and hence facilitate high resolution reservoir characterization. Establish realistic flow potentials for development wells.
Effect of Cement Contamination on Some Properties of Drilling Mud
Authors: Joel O. F , Ndubuisi E. C , Ikeh L.
Published: August 2012

Drilling of oil well is a capital intensive project; hence, the importance of selection of proper mud system that is free from contamination cannot be overemphasized. A poor design and contaminated drilling fluid can be very costly in the life of any well. Therefore, during drilling operations care must be taken to avoid contamination of mud with cement among others. This project details experimental work and findings associated with mud contamination with cement. Also, solutions were proffered on how to manage contaminated mud systems with cement during drilling operations. The result of this work will in no small way help not only the operators but Engineers to manage this concern with dispatch when it arises, thereby minimizing down time and associated costs which affect drilling operations negatively.
Predicting Wax Formation Using Artificial Neural Network
Authors: Adeyemi B. J , Sulaimon A. A
Published: August 2012

Wax formation is a problematic phenomenon in petroleum production operations especially in deep offshore fields. Wax begins to form when temperature falls below the cloud point of the oil as it travels from reservoir to surface lines. Wax deposition may lead to increased pumping power to maintain smooth flow, blockage of flow lines, production delay and even total abandonment of the entire flow line system. A reliable prediction of the onset conditions for wax formation is an important step towards prevention and mitigation of the resultant wax deposition.

Prediction of WAT by most of the existing models deviate from the experimental results due to simplifying assumptions. In this work, Artificial Neural Network (ANN) approach was used to predict the WAT for various hydrocarbon mixtures. The model was trained using different combinations thermodynamic properties of twelve different hydrocarbon fluids subsequently validated with experimental data. Results show that the ANN approach predicts the WAT more accurately than the existing models. The Average Absolute Deviations (AAD%) for the ANN are less than those of the existing models. A combination of molecular weight, density and activation energy as input parameters provided the best prediction.
Investigating the Effect of Electrolytes and Temperature on Rheological Properties of Jatropha Oil Based Mud
Authors: Fadairo A. S. , Tozunku K. S. , Kadiri T. M. , Falode O. A
Published: August 2012

Numerous studies have been carried out on diesel as base fluid in oil-based drilling fluids, and have concluded that diesel oil-based mud is highly environmentally unfriendly and expensive to dispose. One of the ways to avoid these problems while keeping the advantages of oil-based muds is to substitute diesel in muds with environmentally friendly oils, such as Jatropha oil.

This study examined the rheological properties of Jatropha oil based mud in the presence of sodium chloride and potassium chloride salts, and at increasing temperature of the muds. The results showed that salinity and temperature have negative effects on flow properties of oil-based drilling fluids. It also showed that jatropha oil based mud exhibits less adaptability than diesel oil based mud under high salinity and temperature condition, hence there is the need to improve the rheological properties of jatropha oil based mud under this condition. Finally it was revealed that Jatropha oil-based mud possesses great chances of being a technically viable replacement for Diesel oil-based mud.
Economic Investigation and Statistical Database Development for the Oil and Gas Industry
Authors: Dosunmu Adewale , Chimaroke Anyanwu , Evelyn Ekeinde , Oluwayomi Ogurinde , Paul Fekete
Published: August 2012

Nigeria's oil and gas industry is in its budding stage of development and thus requires high technological drive for growth and sustainability. Most operations done in the past have not been preceded by proper appraisal and review to ascertain if there might have been areas for optimization as well as improving on future operations. This has led to huge financial losses in oil business, of which Nigeria takes a substancial percenage of this loss.

In this work, areas of business operations where these losses can be mitigated are identified through thorough economic investigation. The investigations are conducted under professional consultancy services, whose inputs are technology based and reliable at all times.

In this investigation method, statistical data are developed that make history matches as well as identify regularly repeating trends in operations vivid. With the results from this analysis, new decisions can be made to better the outcome of future operations. Key areas for performance improvement are identified and optimized as well.

Finally a database of various findings is developed to properly document useful data for future purposes by consultants as well as industry professionals.

The Nigerian oil and gas business will benefit immensely from this project especially in management issues and in planning future business operations
Interference Tests Analyses of Horizontal and Vertical Well Combinations in a Reservoir Subject to Double-Edged Water Drive
Authors: Adewole E. S.
Published: August 2012

When a reservoir is subject to double-edged water drive mechanism, another well completion may be utilized to (1) intervene in an already watered-out well, for the purpose of optimizing oil production, (2) deliver material through one well to the other, or (3) strengthen confidence on earlier results of reservoir characterization. In all these applications, communication between the wells must not be in doubt. Procedures for analyzing interference tests data to determine the degree of communication between points in such a reservoir system is the main objective of this paper.

Source and Green's functions are utilized in deriving appropriate dimensionless pressure expressions for a reservoir, bounded laterally by double-edged water, and consisting of horizontal and vertical well combinations. To strengthen analyses, dimensionless pressure derivatives are computed from the dimensionless pressure expressions derived. As a late time flow test, external distances between wells are considered in the computations. Well combinations considered are (1) horizontal-vertical; (2) horizontal-horizontal and (3) vertical-vertical. Analytical expressions for analyzing interference test data for each well combination are derived, even if well functions are reversed to strengthen the validity of results.

Results show that, if the reservoir is isotropic, interference test duration should be less than water breakthrough time tDbr ≥ x2eD/Π2 for valid results. Flow time beyond this limit gives only an indication of the strength and responsiveness of the encroaching aquifer. Furthermore, analytical expressions for calculating fluid and reservoir properties depend on the type of well used as active well during the test. Horizontal well combinations would produce earlier interference than vertical-vertical well combinations, given the same anisotropy and rate history. An active horizontal well at interference produces variation of slopes on dimensionless pressures and their derivatives plots between early flow period and commencement of irreversible steady state, while a slope of 1.151 is observed for an active vertical well during the same period. In addition to type curve matching, parameter matching is required for estimating complete reservoir properties. Finally, time of occurrence of interference is directly proportional to area between interfering wells.
A Model Approach of Controlling Coning in Oil Rim Reservoirs
Authors: Onwukwe S. I , Obah B , Chukwu G. A.
Published: August 2012

Water and gas coning in oil rim reservoirs pose serious hindrance to optimizing oil production in the thin oil beds as unwanted fluids tend to replace the oil in the production stream. This invariably limits the ultimate oil recovery. In this study, Semi-Analytical models of estimating critical rate and optimum horizontal well placement was developed to control coning tendencies in oil rim reservoirs. The models was developed through semi-analytical analysis of applying the principle of Nodal analysis to graphically combine gas-oil reservoir system and oil-water reservoir system respectively; with a view to controlling gas and water coning phenomena in gas-oil-water reservoir system. The result was compared with an existing correlation with field data obtained from the Niger Delta oil field.

The models are simple for fast calculations for reservoirs with thin oil zones sandwiched between gas cap and bottom water. It is concluded that the developed models can be used as a tool to make a first pass assessment in the development of oil rim reservoirs anticipated to experience water and/or gas coning during production.
The Nigerian Marginal Field Initiative: Recent Developments
Authors: Adetoba Leye A.
Published: August 2012

The marginal field initiative has come to stay within the Nigerian oil industry since the signing of farm out agreements in 2003 between the multinational oil companies, the Nigerian National Petroleum Corporation and the indigenous companies.

Some challenges such as security of operations, funding, lack of technical know-how, Quota restriction, Lack of infrastructure, Collaboration, Fiscal terms & incentives, Inconsistency in government policies, Gas development, Non availability of rigs, Violation of agreement terms were earlier reported as affecting the progress of the initiative.

This paper discusses the recent updates in the industry as it affects the marginal field initiative especially the improvements and set backs on some of these earlier challenges and new challenges such as the PIB, the Nigerian content law and the call for another bid round.
A Flow Assurance Evaluation of Gas Storage in Depleted Reservoirs
Authors: Alim Chimereucheya N. , Tohidi Bahman
Published: August 2012

Global demand for gas is seasonal, mainly due to fluctuations in its demand at different times of the year. Due to this seasonal variation in demand, gas is often stored during the off-peak period and produced during the peak period.

However, one of the major challenges associated with gas storage in depleted reservoirs is salt precipitation around the wellbore. The dry gas in contact with connate water in the reservoir causes some of the connate water to evaporate to satisfy thermodynamic equilibrium and as a result, salt precipitates when the solubility product of the dissolved ions is exceeded. This deposition of salt potentially leads to pore throats plugging, hence a reduction in the original properties of the reservoir such as porosity, permeability etc over time.

Conventional reservoir simulators do not take this dynamic change in the reservoir properties into account, which leads to inaccurate estimation of the reservoir performance over time. This also results in wrong estimation of the amount of chemical inhibitors required to mitigate flow assurance problems such as gas hydrates, corrosion, scales etc.

This study shows that these changes in the reservoir parameters have an effect on the prediction of conventional models. Hence, reservoir performance should be monitored during the entire field life and the injection/ production data obtained from one cycle should be used to re-define the main reservoir parameters and refine the model for successive cycles.

This study proposes a method of modelling the reservoir performance by taking into account the changes in reservoir and fluid properties over time. It also proposes that in the long term, commercial simulators should be integrated to account for changes in reservoir and fluid properties over time in order to obtain better predictions of reservoir performance.
An advanced simulation model for membrane bioreactors: development, calibration and validation
Authors: Ludwig T. , Gaida D. , Keysers C. , Pinnekamp J. , Bongards M. , Kern P. , Wolf C. , Sousa Brito A. L.
Published: August 2012

Membrane wastewater treatment plants (WWTPs) have several advantages compared with conventionally designed WWTPs with classical purification techniques. The filtration process is the key to their commercial success in Germany with respect to energy consumption and effectiveness, enabled by the optimization of filtration using a dynamic simulation model. This work is focused on the development of a robust, flexible and practically applicable membrane simulation model for submerged hollow-fibre and flat-sheet membrane modules. The model is based on standard parameters usually measured on membrane WWTPs. The performance of the model is demonstrated by successful calibration and validation for three different full-scale membrane WWTPs achieving good results. Furthermore, the model is combinable with Activated Sludge Models.