bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Flaring: Proposed Hydrate Solution as a Feasible Option for the Niger Delta
Authors: Ogolo Naomi A. , Onyekonwu Mike O. 
Published: August 2015

Abstract
Gas flaring in the Niger Delta region of Nigeria is a critical issue and several futile attempts over the years to phase out the ugly practice propagates no imminent solution to the problem. Owing to this fact, there is a need to sort an alternative measure in the interim to halt the practice pending when the issue will be properly addressed and considering the challenges that hinder gas flare abatement using current available methods in the region. The proposed solution in this work entails converting flared gas to solid natural gas hydrate (NGH) at flare sites, store and transport the solid mass to its final destination where re-gasification will take place by heating to recover the trapped gas. The water produced during re-gasification from the solid mass will be sent back to the hydrate plant for re-use. Three benefits of this proposal include saving the environment from pollution, monetizing flared gas and job creation for the masses. However, the major challenges that will face the proposal are easy access routes to flare sites, insecurity at flare stations as sites for gas hydrate plants due to their remoteness and the need for further research to enhance and tailor the available NGH technology to suit the flared gas composition of the Niger Delta.
The process involved in making NGH mainly requires natural gas, water, low temperature (2 to 10°C), high pressure (50 to 120bars) and catalysts (such as Sodium dodecyle sulphate) for increase in rate of formation and stability. The formed hydrates can be preserved at atmospheric pressure under a temperature range of −10°C to −40°C for about two weeks or more. Reported economic analysis shows that transporting natural gas in form of hydrate especially when the volume of gas involved is relatively small from many scattered locations separated by long distances like in the Niger delta case is cheaper than transporting the same volume of gas as LNG. Several challenges that have hindered gas flaring abatement in the Niger Delta will be resolved by this proposed solution.
The Effect of Reservoir Pressure Drawdown on Well Completion/Performance Efficiency
Authors: Joseph A. , Ajienka J. A. , Onyeizugbe S. O. 
Published: August 2015

Abstract
Using a database from Niger Delta, this study developed correlation of well completion/production efficiency as functions of pressure drawdown and sand control type to quantitatively evaluate the effect of pressure drawdown on well performance.
Generally, Completion/performance efficiency declines exponentially with reservoir pressure drawdown. Critical pressure drawdown for various sand control types beyond which significant formation damage will occur are recommended. Apart from external gravel-pack (EGP) and milled casing under-reamed gravel-pack (MCUGP) wells which can tolerate drawdown of ±400 psi, the critical drawdown for other sand control types is ±250psi. With these correlations, drawdown for tubing conveyed perforation can be carefully designed and well completions evaluated. More so, real time prediction of production performance efficiency can be evaluated given the pressure drawdown.
Downhole Electrical Heating techniques in the Orinoco Oil Belt, are they always reliable? Appraisal analysis to Petrocedeño's Pilot Project
Authors: Randy Alvarez 
Published: August 2015

Abstract
This paper gives a brief description about the appraisal analysis conducted for the Down Hole Electrical Heating Petrocedeño's Pilot Project, which has revealed several issues of concern during the evaluation of the oil recovery techniques, focused in the Orinoco Oil Belt (OOB) Field features and the need to have optimized production.
OOB is one of the most prospective assets of Venezuela natural resources. Since its discovery, it has shown a very concerning mobility challenge, which once was considered too high to be produced commercially, also it drove to catalog that oil as tar and sell it as coal. With the development of several technologies and techniques, and the increment of the oil price through the time, the exploitation of the Orinoco Oil Belt Fields has become feasible.
Despite the experience gathered in analog reservoirs in Canada and United States, thermal applications of EOR and IOR, such as SAGD, HASD, CSS, VAPEX, Etc., cannot be implemented in most of the mature fields in the OOB, because their development plans just considered primary recovery, plus thermal materials were not used in producer well completions. Then, it was necessary to choose a technique with low thermal impact to the completion configuration, in order to increase oil production in those developed fields, helping to reach the final recovery factor estimated to primary production.
Since Petrocedeño Field is one example of that scenario and as other fields in the OOB, Downhole Electrical Heating was seen as a possible solution to accomplish with the production requirements. Considering that Petrocedeño has experience with non-thermal techniques aimed to increase oil rate, it was possible to compare and to identify several features that helps to decide which case is best suited to use rather DHEH or the others techniques according to each wells characteristics.
Finally a comparison will be provided and the key issues that helps to decide which scenario is better to use the Downhole Electrical Heating Technique. As a general conclusion, it was pointed that, since the reservoirs are not homogeneous, hence the fields can have more than two reservoirs contained in the same area and may be in the same structure, plus each well has its own challenges according its dimensions, there is not a single solution to have an improvement in the production, and the increment of recovery factor, which has to be finally defined to each well individually.
Developing a Framework for Maximizing Marginal Oil and Gas Field Economics
Authors: Adeogun Oyebimpe 
Published: August 2015

Abstract
The notion to develop marginal oilfields as a means of increasing oil and perhaps marginal natural gas reserves in Nigeria has not been well defined since inception. Many have argued that oilfields regarded as marginal have often times been allocated discretionally because the Federal Government of Nigeria has the sole prerogative to classify fields as marginal. In Egypt for instance, fields with recoverable reserves of less than five million barrels of oil are regarded as marginal. To this end, this paper seeks to redefine the concept of marginal oilfields in terms of concrete and measurable terms, keeping in perspective the recoverable reserves, prevailing fiscal terms and available technology and economic conditions.
Considering the nature of marginal oilfields, a review of the contractual agreement for operators was examined with new fiscal terms recommended. This was necessitated to determine at what point these fields become unattractive to investors with existing technology. A comprehensive economic analysis was carried out showing that these fields are actually a worthwhile investment if adequate incentives are granted by the government. A downward review of signature bonus by 50% had little or no impact on rate on return of investment. A reduction in royalties and petroleum taxes as proposed in the yet to be approved Petroleum Industry Bill 2012, will make the investment in marginal field more rewarding for investors than ly established fiscal terms. Further reduction of oil price below the proposed benchmark of $50 in this work also has adverse effect on the development of marginal oil fields. Financing projects of a high degree of uncertainty poses a challenge to the development of marginal oilfields and various options were suggested including equity financing, technical partnerships, sourcing of loans from local and foreign banks.
Substantiation of Reservoir Lateral Hydraulic Connectivity Based on Integrated subsurface and Production test result - Niger Delta Field Experience
Authors: Adepoju Yaqub , Anyaehie James , Ogbuli Andrew , Balogun Olalekan , Awa Chukwunweike , Mora-Glukstad Miguel , Kakayor Omagbemi 
Published: August 2015

Abstract
Field X is one of SPDC's major gas fields located onshore of Nigeria with six well penetrations and two key reservoirs, A1000X and B4000X,. The field is covered by a 1992 3D seismic reprocessed PSDM with relatively poor imaging quality. This caused uncertainties with respect to the interpretation of possible intra-reservoir fault compartmentilization. These intra-reservoir faults are on the footwall of two major southern and eastern boundary faults. To optimally develop these reservoirs, it was proposed to drill an appraisal well in the eastern fault block, modelled as a reservoir compartment, and subsequently carry out an interference test to establish the lateral hydraulic connectivity of the reservoirs.
A new seismic data was acquired and processed to resolve the uncertainties associated with the poor imaging quality of the 1992 seismic. The interpretation of the new seismic showed similar structural trend, albeit with better clarity of the subsurface images in the fault shadow zones. It also showed continuous seismic reflection loops suggesting a more better lateral reservoir connectivity To better understand the reservoir lateral hydraulic continuity, a multidisciplinary integrated study was conducted using all available data (production tests, Seismic and Petrophysical data).
This paper covers the multi- disciplinary work carried out to establish the lateral connectivity of the reservoirs and its significant cost reduction to the total project cost.
Detection of Water Encroachment into a Marginal Field Oil Reservoir for Ultimate Recovery
Authors: Bisong Anthony Oso 
Published: August 2015

Abstract
One key element of effective well and reservoir management is the application of numerical simulators to solving complex and challenging reservoir issues like aquifer water encroachment into an oil reservoir. Hydrocarbon reservoirs are often in contact with an aquifer that provides pressure support through water encroachment. It is common to speak of edge-water and bottom-water while discussing water encroachment into a reservoir. Bottom-water occurs directly beneath the oil zone while edge-water occurs off the flanks of the structure at the edge of the oil zone. Thus, the prediction of reservoir performance and behaviour usually requires an accurate model. A single-well numerical simulation model was developed using Eclipse® software to detect aquifer water encroachment into an oil reservoir, predict the performance, behaviour and ultimate recovery of the reservoir. Five scenarios of a marginal field reservoir were modeled: no water influx, bottom-water influx, edge-water influx and combined edge- and bottom-water influx. Results obtained from the numerical simulation model were validated with an analytical model MBAL. The results shows that the reservoir depletion without water influx gave the lowest oil recovery and fastest rate of pressure decline, bottom-water influx and combined edge- and bottom-water influx gave the same oil recovery factor while edge-water influx gave the highest oil recovery factor and low rate of pressure decline. The fifth scenario investigated why edge-water influx gave the highest oil recovery factor than the combined edge- and bottom-water influx.
Slug Flow and it's Mitigation Techniques in the Oil and Gas Industry
Authors: Enilari B. T , Kara F. 
Published: August 2015

Abstract
As multiphase production moves to environments of greater water depth and lower temperatures, there poses a huge setback in the assurance of continuous flow from the reservoir through the pipelines to the topside. Slug flow which is a common occurrence encountered in the oil industry is characterized by an alternating flow of liquid and gas resulting in an unsteady behavior of the fluid. In this paper a hypothetical case model exhibiting slugging characteristics is being developed using OLGA. The paper investigates the effect of current slug mitigation techniques such as topside choking, implementation of gas injection and a combination of the two used in the industry. The aim of this paper is to discuss on the results produced from each technique and decide on the most effective approach. From the generated results and research, it was observed a combination of both gas injection and topside choking simultaneously provides the most effective approach in eliminating slugging and increase production.
Subsidence Prediction Using Analytical Approach
Authors: Awasthi Amit , Williams Omolara 
Published: August 2015

Abstract
Geomechanical screening of the A-B fields revealed the reservoir compaction of reservoirs as one of the risks. As a design input for the two offshore wellhead platforms in field A and field B, information on seabed subsidence due to reservoir compaction/subsidence was computed. In order to determine the amount of subsidence an analytical approach utilising the nucleus of strain method from Geertsma was adopted in this study.
An Integrated Multi-Disciplinary Approach to Predict Fluid Contacts in a Partially Appraised Field - A Case Study of Yoko Field in Niger Delta
Authors: Adedoyin Orekoya , Eteobong Etokakpan , Suleiman Ahmed , Basak Prahlad , Ekwealor Jude , Ejiuwa Nworie , Remmy Ugboaja , George Kakayor , Onyeagoro Kachi 
Published: August 2015

Abstract
The need for the estimation or evaluation Original Oil Water Contact (OOWC) prior to reservoir development is very pertinent to appropriate well placement within a reservoir. Oil and gas water contacts are determined via various sources including but not limited to Petrophysical logs, RCI data, Reservoir Simulation, Fault Seal Analysis (FSA), Quantitative Interpretation and Hydrocarbon Column Analogues. This paper focuses on an integrated approach of predicting OOWC using some of the methodologies highlighted above.
The study explores the feasibility of further oil development in the Yoko field to grow production and increase reservoir ultimate recovery. Three wells have been drilled so far in the field and none encountered OOWC. Three (3) key reservoirs account for about 69% of the total field hydrocarbon resource but with significant uncertainty in fluid contacts column (about 132ft) and wide static and recoverable volume range.
An effective and commercially viable field development plan is premised on the reduction of contact uncertainty. Inorder to narrow the contact uncertianty, a multidisciplinary approach has been used and they include (a) Petrophysical Logs (b) Analogue oil column studies from adjacent fields (c) Fault Seal Analysis (FSA) to determine maximum column in the reservoir (d) Quantitative Interpretation (QI) and (e) Dynamic simulation.
The analogue oil column from neighbouring field was used to benchmark the possible oil column for Yoko field. FSA which relies on the sealing capacity of the faults due to the amount of mechanical mixing from fault throws was also considered. The upper and lower limits of the fluid contacts were estimated from acoustic impedance amplitude plotted against depth. The reservoir dynamic models was also history-matched (7 years of production history) to calibrate and ascertain the limits of the possible contacts for the reservoirs.
The result of the evaluation is a significantly reduced volumetric uncertainty range. In one of the reservoir, there was a progressive reduction in fluid column uncertainty from 132 ft to 11 ft. In general 55 – 92% reduction of the initial uncertainty was achieved. This reduced range enabled a commercially viable Development Plan for the field.
Effective Monitoring of Green House Gas Emission - A Laboratory Approach
Authors: Ibemere Uche , Mmata Bella , Onyekonwu Mike 
Published: August 2015

Abstract
The continuous emission of Green House Gases (GHGs) constitutes a threat to both human life and the ecosystem. Carbon dioxide (CO2), Methane (C1), Nitrous oxide (NO2), Hydro-fluorocarbons (HFCs), Per-fluorocarbons (PFCs), and Sulphur hexafluoride (SF6) are usually classified as Green House Gases. The release of these gas molecules into the atmosphere tends to deplete the ozone layer which ordinarily serves as a protective shield from harmful ultra violet rays. The consequent effect of this is global warming, besides the danger of exposure to harmful ultra-violet rays. Though the release of GHGs can occur during combustion of sundry wastes, fossil fuels, agricultural materials, the activities of the oil and gas industry is the major culprit.
To successfully monitor the release of these gases from facilities and specific operations, reliable independent laboratory experimental data is highly needed to assess trends, measure the efficiency of mitigation strategies and initiatives. Accurate measurements of all GHGs emissions are critical for establishing emission baseline and improved accountability.
In this work, flare gas samples were collected from five different flow stations in the Niger Delta region. Gas chromatographic technique was used to determine the bulk molecular composition of the flare gas, using ASTM D1945. Analytical results indicate flow stations A & B flared more GHGs components, C & D flared less while E had inconsistent trend in amount of GHGs flared. All results were quantified and calculated at 95% confidence level. The outcome of this work will aid both the operators of production facilities and regulatory bodies in tracking and controlling the emission of GHGs.
Reduction of Uncertainty in Material Balance derived Original Hydrocarbon in Place Estimate by the inclusion of Fluid Contact History Matching
Authors: Olu Okpani , Hammed Shittu , Idogun Iroro , Anil Ambastha 
Published: August 2015

Abstract
The classical Material Balance equation (F = N*Et + We) is a zero-dimensional reservoir modeling methodology that is used to estimate original oil-in-place volume (N), gas cap size, and aquifer influx (We). The material balance equation is a single equation with many unknowns (e.g. N, m, We); thus the solution to the equation is inherently non-unique. In other words a range of original oil in place (STOOIP) gives good match of the material balance equation. The range of STOOIP solutions of the material balance equation is often too high. In this paper a methodology is suggested for reducing the uncertainty in the material balance derived STOOIP values. In the proposed methodology, the material balance equation is further constrained by history matching the average fluid contacts in the reservoir.
Three case studies were used to illustrate the application of material balance and fluid contact match in STOOIP estimation. The first case study is a synthetic reservoir with a STOOIP of 100 MMBO, initial gas cap and aquifer influx. The result shows that solving only the material balance equation gives a very wide range of STOOIP of 80 - 300 MMBO, while including the fluid contact match reduced the STOOIP range to 80 – 125 MMBO. The second case study is a real reservoir with initial gas cap and aquifer influx. Using material balance alone the STOOIP range was 80 – 800 MMBO whereas including the fluid contact match gave a lower STOOIP range of 100 – 120 MMBO. The last case study also shows a reduction in the range of STOOIP estimation from 50 - 500 MMBO for solving the material balance equation alone to 90 - 120 MMBO when the fluid contacts are history matched. These case studies show that uncertainty in the material balance STOOIP estimates are greatly reduced by matching fluid contacts.
Petrophysical Properties of Nigeria Tarsand Revisited
Authors: Ohenhen I. , Olafuyi O. A. , Ikiensikimama S. S. 
Published: August 2015

Abstract
Heavy oil and Bitumen from tar sands are important energy assets, and have the potential to significantly contribute to the overall energy supply in Nigeria. Nigeria tar sand deposits are found in large accumulations, notably, in huge outcrops in the South-Western region. The initial survey in the early 1980 indicated existence of tar sands in commercial quantity. Petrophysical parameters of these tar sands were measured. However, little information was provided under which conditions these parameters were obtained. Key issues of concerns are the state of technology at that time and how well are the petrophysical characteristics of these sands defined.
In the present work, outcrops samples were taken from seven (7) different locations in the Nigeria tar sand reservoirs. Their petrophysical properties such as porosity, permeability, and water saturation were estimated at surface conditions. Laboratory results obtained showed good agreement when compared with data from existing literature.
Assessment of Injection Pressure Margin in Deep Water Injection Well Design
Authors: Poon Becky B. , Wodu Ebimobowei K. , Ekebafe Abraham O. , Ognane Edgar Mba , Itua Osazua J. , Otoh George A. 
Published: August 2015

Abstract
Waterflooding is a proven secondary recovery mechanism for hydrocarbon production while maintaining reservoir pressures. To achieve the desired voidage replacement ratio, each injector well is designed to inject at a certain rate to support its paired producer. From a safety perspective, it is essential to avoid 1) injection above shale fracture pressure that could result in top seal failure and 2) injection above fault propagation pressure that could result in fault reactivation/propagation. The potential consequences of these hazards are out of zone injection or loss of containment. Following recent major oil spill incidents around the world (e.g. Macondo disaster in the Gulf of Mexico), regulations have become more stringent on well designs pertaining to wellbore stability and reservoir geomechanics.
This paper will showcase an integrated effort at assessing the injection pressure margin and the impact on the detailed injector well designs for a deepwater turbidite field development in the Gulf of Guinea (Nigeria). The technique applied requires a good understanding of the fracture pressures, rock strength, failure mechanism and good drilling and completion practices. To test different scenarios, one well injecting to a deep reservoir and another well injecting to a shallow reservoir were selected for this assessment. Pore pressure, fracture pressure, and injection pressure along the wellbore were analyzed to ascertain the margin between the downhole injection pressure and fracture pressures above and at the proposed casing shoe setting depths. The results of this study provided basis for injector well designs, justification for full field geomechanics modeling, and recommendations for data acquisition while drilling and well reservoir monitoring throughout the injection/production period.