bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alkaline Surfactant Polymer (Local) Enhanced Oil Recovery: An Experimental Approach
Authors: Ojukwu C. , Onyekonwu M. O. , Ogolo N. A. , Ubani C. 
Published: July 2013

Abstract
Alkaline Surfactant Polymer (ASP) local oil recovery process has shown great potential in enhanced oil recovery (EOR). The recovery percentages are encouraging. The fact that these reagents are locally and cheaply sourced is also advantageous. The technique can be successfully applied in producing oil left in reservoirs after primary and secondary recovery process has been exhausted. The reagents used for this work include Irvingia Gabonensis, Lecithin and Palm Bunch Ash (PBA). Irvingia Gabonensis is granulated wild mango seeds (Ogbono, a biopolymer) used as polymer. It has similar characteristics with the xanthan gum that is already in use. Lecithin is a phospholipid and also a surfactant extract from soya bean. PBA is an alkali, and also an agricultural waste product. The reagents were used individually and in combination. Unconsolidated sand was used in the experiment.
The appreciable oil recovery from the experiment buttresses the essence of lowering interfacial tension by the alkali through in-situ saponification to recover 25% oil in place (OIP). The surfactant in this experiment lowered interfacial tension to release more oil out from the sand pores and thus recovered 23.3% OIP. The polymer used increased the mobility and gradually swept the oil trapped in the pores to increase oil recovery by 22.7% OIP. A combination of the reagents used shows that the ASP flood gave a percentage recovery of 27.7% ROIP and an incremental oil recovery of 17.9% above water flooding.
Recovery of Marginal Reserves Through a Cement Packer within Two Production Packers in Dual Completion Strings
Authors: Okoto Francis , Mofunlewi Samuel , Kayode-Sote Olujimi , Okeke Francis , Fatile Olufemi , Enekahi Henry , Atanda Bukola 
Published: July 2013

Abstract
For more than a decade now cement packers have been used to access behind the pipe reserves that have been over looked due to their uneconomical viabilities during the developmental stages of the different reservoirs in a well. This technology has been used mostly to access reserves above the production packers either in a single completion or in a dual completion wells.
Recently, this technology has been extended to marginal reserves found between dual production packers in dual strings completions. In some cases, it has been used to plug off existing perforations within the dual production packers and also used in accessing reserves slightly above or below the existing perforations.
Equally, a new approach was adapted in keeping the tubing free of cement slurry during displacement. This new approach uses a foam wiper ball that is housed in a conventional cement head (designed solely for cement packer jobs) which launches the foam wiper ball to wipe off cement from the Christmas tree bore and production tubing during the displacement of the cement slurry. It also prevents the rigging down of the pump line from the well head connection/crossovers during the wiper ball launching.
This paper describes successful cement packer recompletion jobs done on reserves found above dual production completion and those found between two dual production completion packers using the above techniques.
Application of Experimental Design for Improved Reservoir-Characterisation by Pressure-Transient Analysis
Authors: Uvieghara Tega , Lawal Kazeem A. , Effiom Oghogho 
Published: July 2013

Abstract
Pressure-transient Analysis (PTA) is a useful technique for well-performance analysis and reservoir characterisation. Compared to other subsurface-characterisation techniques, PTA generally provides a more quantitative understanding of the subsurface characteristics over a relatively larger area. However, similar to all inverse problems, the results are often non-unique, largely due to uncertainties in the input data and interpretation model. Although the integration of PTA with other sources of information usually narrows the choice of the interpretation model, the use of uncertain input parameters still undermines the quality of the results while putting the associated business decisions at risk.
To explore the effects of the full range of input-parameter uncertainties on PTA results, this paper describes the combined application of experimental design and response-surface method to analyse and interpret the pressure-transient data recorded by a permanent downhole-gauge during the shut-in of an oil producer in a West-African deepwater reservoir. Specifically, the paper discusses (i) a procedure for establishing the range of input-parameter uncertainties; and (ii) the effects of these uncertainties on the estimated well, reservoir and boundary properties.
Within the parameter-space examined, it is found that the interpreted subsurface properties show strong dependence on the input-parameter range. More importantly, the susceptibility of relying on a single PTA outcome for key subsurface parameters such as permeability and connected volume is clearly demonstrated.
Impact of Matrix Acidizing on Shale Formations
Authors: Morsy Samiha , Sheng J. J. , Hetherington C. J. , Soliman Mohamed Y. , Ezewu Roland O. 
Published: July 2013

Abstract
Matrix acidizing is typically used to remove drilling and completion damage to reservoir conductivity around the wellbore and dissolve calcite in natural fractures. Despite being a common procedure, few studies have investigated the effect of matrix acidizing on the physical properties and oil recovery factors in shales. This paper describes the effect of HCl treatment on porosity, spontaneous imbibition, and crack distribution in samples from the Eagle Ford, Mancos, Barnett and Marcellus shale formations. Samples measuring 2.54–3.81 cm in diameter and 2.54–5.08 cm in length were exposed to acid with concentrations between 0.8–3% active HCl (4 and 15% of 20% diluted HCl). Active acid concentrations of 0.8% were optimal for balancing enhanced oil recovery while maintaining samples structural stability and integrity. The Pre and post HCl treated samples were saturated with Soltrol 130™. Oil recovery was determined by measuring the quantities of oil displaced by uptake of saline water. Recovery factors for Mancos and Eagle Ford shale samples improved from 4 and 16% for non-treated samples to 36 and 71% for the treated samples. In contrast, no change in Barnett and Marcellus shale recovery factors were observed. Porosities were calculated using X-ray computed tomography (CT–scanning). Average porosities prior to acid treatment were 1.6 – 3.7% versus 1.6–10.7% after acid treatment. The CT-scanning studies of treated samples also shows that in the Mancos shale randomly oriented cracks developed, while in the Barnett and Marcellus shales cracks developed along bedding planes; very little crack development was observed in Eagle Ford shales. These results are encouraging for the application of matrix acidizing in shale formations to improve microfractures conductivity at distances along strike from the wellbore.
Seismic-Guided Appraisal and Development: A Case Study from Niger Delta
Authors: Ayeni Olumide , Amaefuna Magnus , Nwogbo Prince , Adepoju Yaqub , Fasasi Roseline , Opadokun Dayo 
Published: July 2013

Abstract
The development strategy for a green reservoir with a huge gas resource needs to be evaluated based primarily on the presence or otherwise of a possible economic oil column below this gas cap, as well as on other pertinent reservoir property distributions. The evaluation process requires the integration of all available and credible geoscience and engineering information to help justify and support the correct assessment of key elements and options in the development strategy.
The only well that penetrated this structure encountered a "gas-down-to" (GDT) within the upper reservoir interval. The objective is to assess the possibility of the existence of an oil rim below the GDT and to estimate the depth of a possible GOC and the associated degree of confidence. This assessment needs to be done to support a robust hydrocarbon development strategy and to secure approvals from regulatory authorities.
This paper details the use of 3D seismic attribute analysis and forward seismic modelling combined with static reservoir modelling and scenario management to delineate the fluid contacts and to constrain the inherent uncertainties. The direct hydrocarbon indicator (DHI) observed on the 3D seismic data across the field exhibits an excellent structural fit and yielded a robust fluid contact definition. The use of quantitative seismic amplitude analysis as well as scenario synthetic matches with real seismic data was invaluable in guiding the selection of a feasible development option and securing the necessary approvals.
Sustainability Risks in the Supply Chain - The Nigerian Content Challenge
Authors: Olatoye Deji 
Published: July 2013

Abstract
With the passing into law of the Nigerian Oil and Gas Industry Content Development Act (‘the Act’) in 2010, a needle's eye has now been transformed into a floodgate for the participation of local enterprises in the oil and gas industry in Nigeria. The oil majors, multinational corporations, which constitute the mainframe of private sector participation in the industry now have to deal with a whole host of new players within their supply chains, with serious implications for procurement management. One such implication will be challenges posed by sustainability risks (Olatoye 2011; Toye 2010).
Sustainability risks are those risks posed by aspects of an organisation's business or operational practices to its sustainability aspirations, expectations or obligations. Traditionally, sustainability risks in the supply chain have been focused on the environmental indicators – thus explaining lingoes like ‘green purchasing’, ‘eco-procurement’ etc (Russel 1998; Erdmenger 2003). However, the enactment of the Act also coincides with increasing emphasis on social as well as economic indicators of sustainability performance (Olatoye 2012).
This state of affairs raises issues on what both procurers and suppliers of services under the Nigerian content regime should envisage in the emergent industry structure. This is all the more so as the procurers of services are not just subject to Nigerian local laws but also a regime of international sustainability requirements, the so-called international corporate responsibility (Michael 2005).
Using the framework of the Global Reporting Initiative and associated standards and principles, this paper draws a chart of the dimensions of commitments which both the supply and demand sides of local content services must look at, as they cement their relationships. It concludes by demonstrating that Nigerian enterprises desirous of taking advantage of the Act will need to look beyond that Act and even the Nigerian legal regime for an understanding of the standard of practices which would be acceptable to their service procurers.
"I-Petro"- Software For The Evaluation Of Oil In Place And Petrophysical Properties Of Petroleum Reservoirs
Authors: Okoli Ugochukwu , Ajienka J. A. 
Published: July 2013

Abstract
Reservoir estimation and evaluation during the exploration and appraisal phases of an Asset has proven very challenging due to the data uncertainties of the Reservoir. This makes the original oil in place calculations erroneous. Some of thePetrophysical data include the permeability, porosity, formation resistivity factor and saturation of water. The Porosity of the reservoir rocks and its permeability can be said to be the most fundamental physical properties with respect to the storage and transmission of fluids. These properties might also have an effect on the Formation resistivity factor, Saturation of water and then the whole Oil in place estimation. Thus, the accurate knowledge of these properties for any hydrocarbon Reservoir, along with the fluid properties is required for efficient development, management, and prediction of future performance of the oilfield Asset. This paper discusses the development (modelling, programming and simulating) of I-PETRO, a software designed to aid the evaluation of Petrophysical data, with reference to data from all the various Depobelts in the Niger-Delta. They incorporate all existing Models and correlations (Global and Regional), which thus allows the user to be able to compare the obtained value with existing correlations. It also helps to evaluate the oil in place. It was developed with Visual Basic 6.0. It is user friendly, reduces complexities in facies analysis, perform Petrophysical properties evaluation and is fully accompanied with an encompassing unit's converter. The first step of achieving the objectives of this project was to develop correlations for Formation Resistivity and Porosity especially for the Niger Delta from 156 data points, these points were taken from different regions of the Niger Delta Depobelts (Northern Delta, Greater Ughelli, Coastal Swamp, Central Swamp and the Offshore Depobelts) and they were compared with Global correlations. I-PETRO software was then developed using an algorithm, which was used to develop the program to estimate Petrophysical parameters and then the oil in place, taking into consideration all the required correlations required for more accurate evaluations.
Optimizing The Technical Limit Value Of Drilling Operations With Proper Bit Selection And Hydraulics
Authors: Okoli Ugochukwu 
Published: July 2013

Abstract
The cost of drill bits represents only approximately 3–4% of the authorization for expenditure (AFE) of well construction, but by their overall performance, affect 15–20% of the overall well cost which can either be positive due to increased rate of penetration (ROP) or negative due to trouble time (TT) losses due to the wellbore or invisible lost time (ILT) due to connection times or other failures. When these costs are considered, the selection of the appropriate bit can be seen to be key of the overall economics of field development. Bit performance represents the achievement of preset objectives which include revolutions per minute (RPM), weight on bit (WOB) and flowrate-hydraulics inclusive. These are a function of the rate of penetration (ROP), footage, and dull grading in a given formation. Bit behavior represents the ability to achieve the required directional control within the confines of a systemized drilling environment. It is a function of the bottom hole assembly, the planned tortuosity of the well (well directional profile) and the operational environment.
In a new development, the typical procedure for the selection of drill bits is for the operator to initially approach drill bit vendors with a data package which contains information (lithology, log information(sonic, density-neutron), and bits graded from offset wells, these are used for the proposed wells as offset information. Drill bit vendors then put together a proposal based on this data and local experience; usually there is no way of validating the bit recommendation except by running the bit and evaluating the dull grade when out of hole, should the bit performance not meet the expectations then a new bit is tried. This method of trial and error exposes the operator and sometimes the cost impact is massive and has its effect on the project.
The technical limit cycle is a conceptual feedback tool for maximizing drilling efficiency, and this paper presents how proper bit selection and proper hydraulics will help to increase the ROP of a well. This in turn helps to reduce all the trouble and invisible lost times which can be created by hole cleaning, high unplanned tortuosity, vibrations, helical/sinusoidal buckling of strings, bit whirls, excessive drags which distorts the planned time of drilling a well. This increases the well cost and increases the technical limit value of the well but the reverse when the right bit is chosen and flat times eliminated.
Drilling Cost Effective Wells By Incorporating Lessons Learnt Into Drilling Operations; OML 126 Wells (Phase 1 FDP)
Authors: Okubor Eleanor , Okoli Ugochukwu 
Published: July 2013

Abstract
The decision to drill new expensive offshore wells is made because of the availability of information that proves the profitability of these new wells and the possibility that these wells can be drilled faster and more efficiently due to experience that has been gathered from drilling older wells under similar conditions. The cost of drilling new offshore wells has not reduced in recent times and drilling new wells to meet production targets has become more challenging while well trajectories have become increasingly more complex thereby increasing the associated costs of delivering such wells. However, new technologies combined with experience have improved the efficacy of operations when drilling relatively challenging wells.
Addax Petroleum Nigeria in its offshore OML-126 operations has been able to overcome technical, logistical and organizational challenges by effectively applying lessons learned from previous operations in its on going operations there by improving drilling performance – reducing time spent drilling and operational costs.
Simple modifications such as using a 36″ bit instead of a hole opener to drill the top hole section improved cementing, setting the seal assembly after cementing operations rather than before cementing to prevent the accumulation of debris around the seal assembly area improved the efficiency of setting the seal assembly, optimizing the screen sizes while drilling the reservoir section reduced the time spent conditioning the mud to Production Screen Testing (PST) quality for completion operations (running Expandable Sand Screens (ESS) and Stand Alone Screens (SAS)), and has also considerably reduced the time for completion operations, other factors like continuity, in-house competition, improved communication and knowledge management has helped increase the efficiency of operations and saved cost».
This paper expounds on these and other changes that were carried out during the Phase I development of the Okwori field and how they reduced costs and saved time while achieving the goals that were set prior to commencing the drilling campaign.
Classification and Management of Liquid Loading in Gas Wells
Authors: Joseph A , Sand C. M , Ajienka J. A. 
Published: July 2013

Abstract
Liquid loading in gas wells is the accumulation of liquids (water or condensate or both) in the wellbore due to pressure decline. It occurs in vertical or deviated wells during production from natural gas reservoirs as a consequence of condensation and coalescence of liquids from gas streams. This is common in both offshore and onshore production systems and results in the simultaneous flow of gas, liquid hydrocarbons and water.
Both water vapour and intermediate hydrocarbons can condense, depending on the composition of the gas, the temperature and pressure within the wellbore. Liquid loading has remained a menace and a fundamental problem in gas wells as all gas wells will undergo this phase in their productive life cycle. It is more pronounced in aging fields but can also occur in new wells having poor completion designs. When improperly managed, liquid loading can cause not only a drastic reduction in production but also pose a potential challenge of killing the well.
Several methods are available in aiding and managing production when severe liquid loading occurs, but there is no current solution available in preventing its occurrence in the industry
This review considers a broad perspective of how liquid loading has been managed over the years and develops classifications for liquid loading problems based on the sources of the liquids, the severity of the problem, the preventive measures and the treatment strategies available in the industry. A comparative analysis of some of the predictive models was made along with a new model using Matlab. The result shows that at pressures below 2500psi and pressures above 5000psia; the modified model perform better than Turner et al's model whereas at pressures between 2500 and 5000psia, Turner et al's model performed better than other models.
This work is intended to provide a "first aid" guide to professionals and early career engineers in one package – identifying different types of liquid loading problems and the available and best techniques in managing it; thus accelerating quick decision making and intervention in gas fields for the oil and gas industry.
Prediction of Oil Rim Presence from Compositional Gradient Theory – A Case Study from Niger Delta Reservoirs
Authors: Joseph Peter , Imo-Jack Otavie 
Published: July 2013

Abstract
Fields in the Niger Delta Region in Nigeria typically comprise of stacked multiple reservoirs, sometimes with more than one culmination in a particular sand unit. Due to the occurrence of numerous hydrocarbon-bearing intervals in these stacked reservoirs, it is often unlikely that an appraisal well downdip of the structures will provide fluid contacts information at all levels in the field. Based on this fact, some gas-bearing reservoirs with relatively small Hydrocarbon In-Place volumes cannot be economically developed owing to the requirement of a dedicated appraisal well to establish the presence or absence of an oil-rim. The presence of an oil rim in a predominantly gas reservoir can go a long way in influencing the long term development philosophy. For example, the presence of an oil rim could lead to delay in gas cap production, and thus affect an operator's ability to meet gas demand contracts. An alternative approach that can verify the presence of oil-rim without a dedicated appraisal well will aid early development of these reservoirs.
In this paper, the use of compositional gradient model as an alternative way of predicting presence of oil-rim in the Niger Delta reservoirs is presented. The model is calibrated with data from several reservoirs with known fluid contacts, and then applied to gas reservoirs where fluid contacts are unknown. The results show good comparison with log, core and amplitude data when the fluid column is continuous and not interrupted by fluid infusion or geological barrier.
The theory of using compositional gradients to establish the presence of oil-rim has been widely investigated around the world. The theory is based on compositional variation along hydrocarbon column where the forces at play are majorly arising from gravity, chemical and thermal forces. In a typical hydrocarbon bearing column under gravitational forces, the mole fraction of lighter components decreases while that of heavy fractions increases from top to base of the column. As a result, fluid composition and properties also vary. This is the basic theory underlying the use of compositional gradient model to predict oil rim presence.
In the Niger Delta where the CAPEX for a new well is in the region of $25 million for an onshore well, this approach becomes a cost-effective way of confirming the presence of oil-rim, and therefore aid the profitable and speedy development of the asset.
Prediction Of Rate And Volume Of Oil Spill In Horizontal And Inclined Pipelines
Authors: Salufu Samuel O , Ibukun Samson O 
Published: July 2013

Abstract
Accurate prediction of total quantity of oil spills has become essential in designing bioremediation technology for effective remediation, cleanup of oil polluted environment, and for proper assessment of oil polluted environment.
Hydrodynamic principles were used to derive a simple analytical model to predict the rate and total volume of oil spills in both horizontal and inclined pipeline. The model result was validated with experimental result at various leakages pressure and leakages radii.
The results indicate that the model values match with the experimental values. The average standard