bluuebunny/crossref_metadata_2025 huggingface dataset:
A CFD Approach for Predicting Paraffin Deposition in Oilfield Installations
Authors: Otung D. A , Osokogwu U.
Published: August 2012

As the high demand for fossil fuel pushes the frontiers of oil exploration and production into more hostile environments, issues associated with flow assurance have become increasingly important. This is especially true of paraffin wax precipitation and deposition in areas of reduced temperatures, such as the Polar Regions and in deep sea environments. In order to reduce costly remedial operations aimed at removing pipe/tubing blockages resulting from wax deposition, it is essential to predict when, where and how much paraffin wax is deposited during the working life of oilfield installations. In this study, a computer application model capable of predicting wax precipitation and deposition in oilfield installations under various conditions of flow was developed. Thus, a computational flow dynamics (CFD) program named "WD-Predictor" using C++ language was designed and developed with mathematical models that approximate the physical behavior of wax crystallization and deposition systems such as; Property Transport Models (Energy, Momentum and Mass), Thermodynamic Equilibrium Model and Wax Deposition & Erosion Model. The mathematical models developed were discretized while numerical solutions to the discretized models were then developed using appropriate algorithms and pseudo-codes. The "WD-Predictor" was used to estimate the Wax Appearance Temperature (WAT) of three crude samples. The results obtained were compared to an experimental results published; Exp.WAT for oil sample 1 was 87.800°F and Predicted was 89.888°F, for oil sample 2- the Exp. WAT was 114.35°F and predicted was 115.76°F and for oil sample 3, Exp. WAT was 72.950°F while Predicted was 70.620°F. Again, WD-Predictor results were compared with the experimental data extracted from Cordoba and Schall (2001). Above all, WD-Predictor output on wax deposition thickness was also compared with the enthalpy-porosity model proposed by Banki et al. (2008) and in all the WD-Predictor showed consistence in results, in line with these published experimental results. Finally, WD-Predictor was validated with a well-tested simulator PROSPER™ on pressure and temperature profiles using Beggs & Brill Correlations.
Furui's IPR Model Correction and its Application in Horizontal Well Cresting Control & Inflow Control Device Installation
Authors: Kareem Lateef A. , Emeka Omeke James
Published: August 2012

The problem of reservoir heterogeneity has made the continued use of Inflow Performance Relation (IPR) models developed on the assumption of homogeneity impractical. Furui in 2003 (and previously Butler in 1994) solved the problem using fully penetrating well idea so that the model can be applied to different sections of the reservoir.

This paper corrects two errors in Furui's model. The first error is the use of arithmetic mean of radii to evaluate the elliptic surface area of the well when an anisotropic reservoir is converted into an isotropic equivalent. This was corrected using an equivalent cylindrical surface area. The second error is the use of a planar isobaric surface at the end of the radial flow region instead of a circular one. These corrections gave the model a better performance-average of 99% against 96% by the original version, when compared with line source solution obtained by using Green function.

Equating the hydrostatic and viscous pressure differences between the well and the water oil contact (WOC), a cresting equation that predicts the critical production rate and pressure drawdown for each zone needed to prevent water (or gas) encroachment was developed.

Based the IPR and cresting equation, this work presents a mathematical concept on installation of Inflow Control Device (ICD) so that production from each zone is designed according to its requirements.
Sanding Prediction using Rock Mechanical Properties (A Parametric Study)
Authors: Joseph A. , Akubue L. C , Ajienka J. A , Oriji A. B
Published: August 2012

Sand production is described as the production of load bearing sand grains along with the produced reservoir fluids. Problems associated with it include: blockage of tubular, formation damage, casing collapse, erosion of facilities, leakages and spills, environmental issues and disposal problems. Predicting the potential of sand incidence is an important decision that petroleum engineers must make, at the time of well completion to avoid unnecessary sand control expenses. In this work, a parametric study was made to investigate the impact of various mechanical rock properties using Omar Abdulaziz Almisned's prediction model. Different diagnostic plots were made to establish unique trends for five cases using five different rock parameters and compared with the critical pressure at various depths. It was observed that the critical pressure increases with the increase in Shear modulus, Young's modulus and bulk compressibility, but decreases with the increase in poisson's ratio and bulk modulus. In addition, it was observed that the plot, (1/k)/(ts/tc)x1010, gave a close and consistent trend. This parametric combination has the same dimension as rock compressibility. This model will serve as a useful tool to estimate critical well pressure causing sand prediction, predict sand production and can also be used to perform parametric comparison of different mechanical rock properties.
Real Time Flow Estimation Using Virtual Flow Measurement Techniques: A Field Application in Intelligent Well Completion
Authors: Ajayi Arashi , Fasasi Toyin , Okuns Godwin
Published: August 2012

Intelligent well completion has been used in various applications including but not limited to fields with multiple reservoirs. In such applications, estimation and allocation of downhole flow rates at each reservoir are critical for efficient reservoir management. One way of estimating downhole flow rates is the deployment of dedicated physical zonal flowmeters, using virtual flowmeter techniques based on the architecture of the intelligent well completion or combination of both options.

This paper describes the methodology and field wide application of using real time data from an intelligent well to estimate flow rates without the need for a physical flow meter. The real time data are from the installed downhole gauges in the well. This is combined with interval control valves, static and dynamic well information to provide reliable estimate of well production rate.

Since downhole pressure, temperature and ICV information is already available in an intelligent well, this technique provides a lower cost option of obtaining zonal and total well production and injection rates. The methodology used incorporates analytical choke equations, tubing performances, and nodal analysis (inflow performance relationship) with other reservoir parameters to build a flow estimation algorithm and model. Various downhole equipment (interval control valves, packers, pressure and temperature sensors etc) and related well information are captured into the system to set initial and final boundary conditions. Well test data can be used to calibrate the system and improve the accuracy of the model.

In the field application described, results vary from well to well with field average estimates within +/−10% when compared to measurements from normal surface metering systems. Well tests from the surface measurements were used to calibrate and improve accuracy. The result shows an operating envelope that covers a range of pressure drop across the ICV.

The method is capable of handling single and two phase system. Further enhancements are been made to handle multiphase and systems outside the steady state regime. In addition, enhanced data filtering techniques implemented in the system help managed noisy data.

The analytical techniques described enhance digital oilfield capability in optimizing production through affordable flow rate estimation for intelligent wells. The technique presented can also be used to increase the reliability of applicable wells since no additional physical hardware is required.
Practical Application of the IPSM in Resolving Gas Availability Challenges and Overall System Optimisation to Maximise Production
Authors: Thomas Ayoola Olakunle , Tohira Shakioye , Edidiong Taiger , Linus Nwoke
Published: August 2012

With global energy demands on a steady increase, it is important to ensure hydrocarbon production optimisation and sustainability while minimising production process impact on the environment. As a result, technologies and processes that improve response to production challenges and guarantee optimisation and sustainability of production and products utilisation, especially associated gas, have become more relevant in the oil and gas industry.

The Integrated Production System Modelling (IPSM) tool is a means of simulating actual production systems and assessing their responses to changing production scenarios, challenges and the impact of various solutions on production systems before effecting the changes in the field. IPSM was used to assess the options of ensuring gas availability to meet the minimum turndown ratio of the associated gas gathering (AGG) low pressure compressor and ensure optimal oil production from a field in the Niger delta of Nigeria. Declining gas production from the producing oil wells in the field poses the challenge of keeping gas production above the minimum required turndown ratio for the compressor to run. A multi-disciplinary review and production system optimisation identified the options of re-routing either of two producing oil wells with significant gas production rates from a nearby field to the production facility of the field of interest to ensure the minimum required gas is always available. The impact of re-routing each of the proposed wells on the overall production system efficiency was analysed using IPSM with a view to optimising oil and gas production without compromising recovery from the wells in the field of interest.

The results from the analysis indicate that IPSM is a robust tool for analysing the various options and optimising the required solution. The impact of the different options on overall system health was quantified and greatly enhanced the business decision making process with overall benefit of provision of required LP gas to run Field Y compressor, safeguarding the invested fund of building the AGG plant in addition to a projected 5MMscf/d sales gas.
Acid Stimulation by Bull-heading and Back-production: The Bonga Experience
Authors: Okoh Ehimhen , Olatunbosun Olugbenga , Ogunsina Oluseye , Uche Enor , Eta Kingsley , Oduola Lukman , Beldongar Maye
Published: August 2012

Bonga producer (Well-X) became severely impaired during a series of interventions (to address SCSSV failure), with oil potential dropping from 18 to 3 kbod. The Well and Reservoir Management team believed the initial impairment was most likely caused by fines migration and secondly by fluid (MEG and brine) losses to the formation during interventions. A two-fold treatment was recommended –solvent (surfactant) and half stre gth mud acid to target the two impairment mechanisms. Considering the relatively low productivity and remaining reserves, the downside risk was low from a subsurface perspective. The major concerns were related to HSSE and integrity risks pertaining to unspent FPSO. Lessons learnt similar jobs by other acid flow-back to the Bonga from successful executions of Operators enabled the Bonga team to demonstrate the necessary risk management and purs e the concept towards execution.

To minimize cost, the recommended deployment method was by bull-heading the treatment from the Field Support Vessel, via a flexible hose connected to the tree, and subsequently to back produce the well fluids to the FPSO with injection of Soda Ash to neutralize any unspent acid on the topsides. The key challenges that needed to be addressed were: Identifying an appropriate stimulation recipe, Ensuring adequate pump rate of stimulation fluid given limited pressure rating of the flexible hose, Managing flowback of unspent acid to topsides, Metallurgy compatibility with the stimulation fluid, ydrate risk and Production of H2S from chemical reaction. Full integration of the various functional aspects was essential for effective planning and execution.

The Well-X stimulation led to an increase in production frrom 3 to 22 kkbod, with PI improving from 1.4 to 86 bpd/psi; a PIF of 60. Industry experience shows that gaains from mud acid stimulation to attack fines can typically be sustained for up to 12 months, while the partial gain from surfactant to remove MEG/brine impairment is expected to be sustained permanently. TThhis success paves the way for further acid stimulation in the Bonga field where fines migration is typical among producers, and provides opportunities for production acceleration in the field and other upcoming developments.
Technical Evaluation of Secondary Oil Recovery Methods, A Case Study on one of the Iranian HPHT Carbonate Reservoirs
Authors: Sajjadian S. , Ataabadi V. Mahmoudian , Dalaei M.
Published: August 2012

The reservoir under study is a HPHT (high pressure-high temperature) reservoir with high amount of H2S and asphaltene. It has more than 1 billion of recoverable oil as static geological model estimated but the problem is the only drive mechanism is Solution gas drive and it has no active aquifer so although it had good flow potential but what if it drops lower than bubble point pressure? Dynamic model showed it was to deplete quickly. By using new reservoir management techniques and enhanced oil recovery in order to pressure maintenance one can recover a lot more oil.

The scope of this project was to evaluate in terms of impact of surface facilities, reserves and recovery factor of using gas injection and then different fluid composition for this field's gas injection

Water Injection Rich gas corresponding to the associated separator gas to be re-injected to reservoir Lean gas corresponding to the associated separator gas to be re-injected to reservoir after condensate removal

There are 40 wells in this fields and this was possible to change function of production well to injector if needed.

A team of Reservoir, Production, Process, Facility and Environmental engineers worked on the possibility of Secondary recovery by injection and its challenges.

Simulation models were run for different scenarios and realizations and the best composition of injection fluid was selected by considering reservoir rock and fluid data and different injecting fluid composition and different injection pressure.

After comprehensive study and technical evaluation it was found that. Miscible gas injection was the best scenario allowing 0.66 BSTB Recovery increase and 9 years longer plateau compared to Natural depletion.
Field Development: Reservoir Development Strategy, A 3-D Modeling Approach
Authors: Agina Henry L. , Ahunanya Dike O. , Ekebafe A. O.
Published: August 2012

This paper presents a proposed development plan of an oil onshore reservoir replica. The reservoir comprises sandstones with moderately high porosity/permeability distribution. Recoverable oil from the reservoir is 527 million barrels through primary energy, found to be gravity drainage and an underlying aquifer. The reservoir sits at 7840ft from below sea level with area of 2400acres.

The structure of the reservoir showed three (3) major faults compartmentalizing the reservoir into four (4) fluid-in-place regions, two (2) of such accounted for 70% of the water production. Smart wells were drilled to control water production from such zones, wherein Inflow control valves (ICVs) were designed and optimized for selective shutoff or delay of water production, in effect increasing recovery. Horizontal and highly deviated wells' trajectory and displacement was also considered because of potential non-sealing faults that divided the reservoir into layers or compartments.

Optimization of proposed development plan was done with objective function of maximizing ultimate recovery (UR) via fluid production till reservoir abandonment. This could be used proxy optimization models for part or group of reservoirs in a big field.

This paper reiterates the importance/role of reservoir modeling and simulation with and necessary sensitivities that will assure optimized full field reservoir development.
Interference Testing in Anisotropic Composite Reservoirs with Leaky Faults – A 3D Semi-analytical Approach
Authors: Ezulike D. O , Igbokoyi A. O
Published: August 2012

This paper illustrates how horizontal well interference tests in composite reservoirs can be analyzed using Tiab's direct synthesis (TDS) and curve matching techniques; providing insight into the three dimensioned nature of associated fluid flow.

Resetroir heterogeneity is the reality and has been studied under various contexts including composite systems, multilayered systems, dual porosity systems, dual permeability systems, triple porosity systems; each with its corresponding flow anisotropy. A composite resen oir is one with multiple compartments; each having distinct rock and fluid properties separated by geologic discontinuities. Importantly, this reservoir system is encountered often in fields due to the geologic interplay between depositional and tectonic forces.

For the first time using transform methods, a general customizable three dimensional point source semi-analytical solution for the drawdown response in composite clastic systems separated by a leaky fault is developed. This solution is then converted to line source for horizontal well observers 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 semi-analytical solution is achieved using a simple computer program which can generate type curves in a computationally cheap and effective manner.

Sensitivity analysis conducted on generated interference responses with respect to areal permeability anisotropy, well position, reservoir dimensions, dimensionless fault conductivity and mobility ratios in composite clastic reservoir systems reveals that the response is a convoluted function of resetroir properties from both compartments and the separating semi-permeable medium.

It is observed that the intersection time between the long-time approximation of both observer pressure drawdown and observer pressure derivative is unique - from which producer hydraulic diffushdty could be obtained. Tiab direct synthesis (TDS) of resetroir parameters from the resulting equation is examined. From 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, especially if an existing well in the other compartment can be used as an observer.
Improving Recovery from Oil Rim Reservoirs by Simultaneous Gas and Water Injection
Authors: Onyeukwu I. H. , Peacock A. , Matemilola S. A. , Igiehon O.
Published: August 2012

This paper presents the results of the study that was initiated to investigate the incremental benefit of gas and/or water injection in the production of oil rim reservoirs. Due to the nature of the project, emphasis had been on maximizing oil recovery. Consequently, only the incremental oil recovery was used to screen development concepts with a view to optimizing the overall economic value of the concept.

This paper includes reservoir simulation on oil rim development with gas and/or water injection with sensitivities on: 1) Permeability anisotropy, Kv/kh 2)GOR relaxation policy 3) Aquifer strength 4) Oil Column Thickness (Ho) 5) Well placement.

Results of this study suggest that simultaneous gas and water injection (voidage replacement maintained) could increase recovery factors by upto 15% of STOIIP.
Development of a Model to Calculate Rig Power Requirements for Geothermal Applications
Authors: Bello O , Teodoriu C.
Published: August 2012

Many methods have been used to reduce power consumption of rig systems in drilling, completion and workover applications. However, the effects of various parameters on rig system power consumption have not been previously investigated for geothermal operations. Study of such issues is of significant importance because it enables estimation of possible range of parameters where rig system deployment for geothermal drilling operations can be economically viable.

The purpose of this study is to create a method which can help engineers choose a combination of parameters that minimize power consumptions. In this work, a computational approach is presented in quantifying rig system energy consumption associated with geothermal drilling operations. The corresponding analytical approach in quantifying energy consumption of geothermal rig system is shown. The paper is geared towards achieving effective and efficient geothermal drilling processes by researching into trends in energy losses.

The results obtained show the feasibility of the applied procedure and provide a methodology for determining optimal conditions for geothermal drilling operation, which can substantially improve rig power efficiency from their current states. The parametric study also demonstrates that the decision of the geothermal drilling rig operating policy at the design stage can have a significant effect on the power savings and costs.
Deepwater Drilling Operations Challenges of Exploration Well in Alpha Block, Gulf of Guinea: Lessons Learned
Authors: Onugbolu Olisaka , Rodrigues Carlos , Maueler Roberto , Lewis David Wayne , Loyola Charles
Published: August 2012

Deepwater environment pose several challenges and constraints on well drilling operations. These challenges include but are not limited to harsh and hostile weather conditions, distance from shore, water depth, personnel safety and piracy in some cases. All these can be successfully managed and operational excellence achieved through innovative approaches.

The aforementioned challenges, if not recognized and adequately addressed especially during the well planning phase, will ultimately manifest as unscheduled downtime, high-risk exposure, low operational performance and above all, increase in overall well cost. Petrobras and her partners recognized these challenges during the planning phase of a recent exploration well and put measures to optimize the operational efficiency of the well.

The exploration well is located in deepwater ALPHA block offshore outer continental shelf waters of Nigeria; western flank of the Niger Delta. The acreage spans 853.5 km2. The water depth range from 1600m to 1800m and an approximate round-trip sailing time of 60hrs (about 350 nautical miles) from the logistics base. Round-trip flight time of 1 hour (about 80km) from the nearest airport. Thus, the environment is considered remote with high level of logistics challenges.

This paper presents some of the innovative approaches employed in managing the challenges which led to the positive results achieved. It is imperative to note that our intent is to share our experiences and lessons learned in this well operation with the industry so that drilling operational process can be improved and well cost reduced significantly.
Relative Rock Strength Determination from Well Logs - Comparison of Deepwater Fields, Offshore Nigeria.
Authors: Jenakumo Timipere , Adoghe Leo-Andrew , Aniekwe Osita , Nwosu Chike
Published: August 2012

Elastic constants (Poisson ratio, Young's and Bulk Moduli) and acoustic velocities are often used to specify the strength of rock materials. An understanding of reservoir rock strength and geomechanical issues related to drilling and producing from unconsolidated formations are essential for well completion and injection design as well as production performance and optimization of recovery.

Typically, laboratory tests such as unconfined compressive strength, triaxial strength test from cores provide stress and strain parameters from which the elastic constants are derived, and rock strength is determin d. In the absence of these laboratory tests, this study has used well logs (density, compressional and shear wave velocity) to derive the dynamic rock mechanical properties and assessed the relative rock mechanical strength for four select Nigerian deepwater fields.

This work investigates the possible impact of formation strength of four deepwater fields with respect to causes of drilling, completion and injectivity issues. Water injector wells in Field B1 are seen to be quite successful, whereas this is not the case in field A1.

The studyresults provide some insight into the relative degree of consolidation between these fields. Comments on the completion practices and injection into similar rocks in these fields will be based on the determined relative rock strength.
Effective and Innovative Approach to Integrating Static and Dynamic data: A key to Volumes Optimization in Erha Field
Authors: Mudi K. C. , Idih R. E. , Sarumi O. S. , Etta C. O. , Ejayeriese A. O. , Nwogbo N. C. , Oke A. A.
Published: August 2012

Erha field is a stacked deepwater slope confined channel complex system. Vertical and lateral communication between channel sets and individual channel sands is hampered by a series of cross cutting faults and a complex vertical channel stacking pattern. The principal depletion mechanism in Erha is gas-cap drive with support from both gas and water injection to effect simultaneous closure of the GOC and the OWC around producer completions. Erha field currently produces about 85 kBOPD & 340 Mscfd gas with a STOOIP of 1.46 GBO and a 34% recovery factor. Year End 2010 recovery is 220 MBO.

A key challenge for interpretation and surveillance is the identification of flow barriers/baffles. The complex geology and degree of compartmentalization make it difficult to define reservoir connectivity between the channel complex sets. Gas channeling through high permeability pathways is a major challenge in Erha with 6 wells shut in due to high GOR and the remaining 9 producers showing elevated GORs. A key opportunity therefore is the development of a reservoir management plan that accounts for these complexities and performance.

The Erha subsurface team, including representatives from geology and reservoir engineering, has identified potential baffles and barriers by integrating static and dynamic reservoir data. As a result, a revised gas injection strategy was initiated, significantly mitigating gas channeling and thereby improving oil rates, prolonging well lives and maximizing the asset value. Additionally, the improved description of reservoir connectivity underpinned the development of new geologic and simulation models that will be used in the determination of potential bypassed oil and infill drill wells/completion strategies.
HSE Culture as a Panacea to redefining HSE Excellence and Sustaining HSE Best practices
Authors: Bada A. J. , Ugbebor J.
Published: August 2012

The paper is a follow-up in achieving HSE excellence through institutionalizing HSE. Several tools are used in achieving HSE excellence but HSE culture has been used in this paper as a forerunner to a holistic HSE practice that is sustainable. It explains the need to redefine HSE excellence after ensuring that HSE culture has been engrained in all facets of the organization to the extent that HSE activities are performed as part of normal daily routines. The emphasis in this paper is based on experience which shows that HSE is being seen in the light of occupational safety than for process safety. Varied illustrations of disasters were highlighted showing the importance of redefining HSE excellence through HSE culture. Many organizations despite their HSE Culture programs still experience sudden HSE backwardness. Barriers to positive HSE culture was described and how to develop positive HSE culture in an organization. Pro-active safety in preventing skill-based errors, mistakes and violations to achieving HSE excellence was also mentioned. Many organizations have failed to realize that moving past the traditional HSE culture to redefining HSE excellence is the only way to achieving results. Achieving institutionalized HSE performance required HSEMS that includes Active leadership, HSE risk Assessment, behavioural change program, Leading and lagging HSE Performance Indicators, empowerment and dialogue. It concludes that good HSE culture is critical to prromoting HSSEEMS implementation, conducive for risk reduction in all organization's activities and, ensures productivity. Practicing HSE excellence moved beyond HSE culture to ensure that HSE performance is a journey and not a destination.
Coal Bed Methane System Modeling – Integrating Reservoir, Wells, and Facilities
Authors: Ori-Jesu E.
Published: August 2012

Coalbed methane (CBM) holds promise of relatively clean, stable natural gas supply in the emerging global energy map. This project summarizes the integrated modeling of a unit of a coalbed methane reservoir-well-surface facilities system. The pro ect demonstrates the resulting reservoir and system response for different well fluid and pressure conditions, for a range of artificial lift parameter and surface facilities constraints. An economic cost model is also linked to the coupled system, which incorporates ranges for gas prices, water handling costs, capital and operating costs and discount rates. The instant capability to examine the possible net present values and internal rates of return for a given production stream of gas and water is also demonstrated. The simultaneous optimization of the reservoir, well, surface and economic models in a single simulation run made possible by proprietary oil industry software enables the observation of the system behaviour instead of just the reservoir as has been mostly done in industry. The reservoir effects on this coupled system are presented to explain important considerations in CBM feasibility considerations. The resulting model is scalable to deal with larger fields and well patterns.
3D Integrated Reservoir Modeling of a Structurally Complex Niger Delta Reservoir
Authors: Dike Francis , Osemoahu Omobude , Olatunji Idris , Mbursa Nayagawa , Amrasa Kefe , Aboaja Ugochukwu , Osho Rotimi
Published: August 2012

Accurate reservoir performance prediction m a structurally complex brown field is very important for generation of reliable production forecasts, location of possible by-passed oil estimation of reserves and optimal well/ reservoir management.

Reserves estimation is one of tire key functions of Petroleum Engineers and it requires an integrated approach for tellable estimates to be made. The traditional techniques include Decline curve analysis, Material balance. Volumetric. Analogues and Numerical Reservoir simulation.

Reservoir X is a structurally complex reservoir nr Field Y in the Niger Delta Basin. It came on stream in 1970 with 3 wells. Eight additional wells started production between 1972 and 1990. Five infill wells were drilled and completed between the years 2000-2005. However, due to operational and technical reasons (which are beyond the scope of this paper), 2 of these wells are yet to be put on production Over the years the reserves associated with these 2 wells have been estimated by analytical means (Volumetric and Material balance methods). However, there was the challenge of investigating the impact of fluid saturation changes around these wells, occasioned by the production fiom offset wells, on the reserves estimate obtained fiom material balance techniques These challenges necessitated the full field 3D integrated reservoir modeling

The reservoir contains 9 blocks in which 8 are densely faulted. The material balance analysis, being, at most, a onedimensional model, was deficient in robustly assessing the subsurface uncertainties which includes fault sealing potential and fluid contacts movement.

This paper discusses the techniques employed in building die static and dynamic models and shows a comparison of the reserves estimate results fiom analytical techniques versus 3D dynamic estimates.
Cleanup of Crude Oil Polluted Sites Using Arachis Hypogaea L. (Groundnut) and Biostimulants
Authors: Ekeh-Adegbotolu U. V , Ekeh O. M , Wegwu M. O.
Published: August 2012

Oil spill is a major problem in the Niger delta region of Nigeria. For every 10 spills that occur, there could be more than 5 affected lands. The increased role played by petroleum in Nigeria's economy has resulted in adverse environmental impact associated with oil exploration and exploitation. Some of these adversities have included soil deprivation and degradation. The soil quality for agricultural activities is altered by nutrient pauperisation, due to the presence or increase in oil and toxic metal concentration. Other impacts such as poor water quality affect surface and groundwater system as a result of oil spill and associated chemicals.

In recent times, the zero pollution campaign has been paramount in finding ways of combating oil pollution. The methods include chemical, thermal, bioremediation and phytoremediation. Some of these methods are very expensive and hazardous to the environment.

This paper examines the application of a common crop, Groundnut for the cleanup and remediation of crude oil polluted sites as a cost effective and profitable means of crude oil remediation. The research data shows the usefulness of planting groundnut for the cleanup and remediation of crude oil polluted sites. The research also investigates the level of crude oil cleanup through the use of biostimulants to aid the cleanup process.

The study shows about 73% oil clean up or extraction over a short period of 8 weeks compared to the 21 weeks life span of the plant. It also highlights the importance of biostimulants in crude oil remediation. This allows for enhanced remediation of crude oil polluted sites in a shorter time frame. This process is a pure and natural process for soil nutrient replenishment and enrichment. The harvested crop if not edible, could be used as a source for the production of biogas, an alternate energy.
Evaluation of Emulsion Treatment Using Different De-emulsifiers
Authors: Dosunmu A. , Otikiri A. E. , Fekete P. O.
Published: August 2012

Water in oil emulsion occurs at many stages in the production and treatment of crude oil. About two thirds of the produce of every new oil field exists in the form of water-in-oil emulsions. The emulsion stability results from the presence of interfacial barrier preventing coalescence of the dispersed water droplets; this is due to the present of polar components such as asphaltenes, resins, and wax and naphtenic acids in the crude oil. Therefore, before transporting or refining the oil, it is essential to separate the water for economic and operational reasons. In this research, three demulsifiers were used (Igepal co-720, Tween 40 and Tween 20) with the experimental work performed under room temperature. The results obtained with chemical demulsifier Igepal co-720 with Hydrophilic-Lipophilic Balance (HLB) of 14 were {31, 27, 24, 22 and 22%} of water separated from 5,4,3,2 and 1 ml concentration respectively at 60 to 120minutes optimum separation time. Similarly, from chemical demulsifier Tween 40 with HLB of 16 was {80, 74, 72, 70 and 55%) water separated from 5,4,3,2, and 1ml concentration respectively at 60 to 120minutes Optimum separation time. Finally, results obtained from chemical demulsifier Tween 20 with HLB of 17 were {95, 83, 67, 60 and 50%} respectively of water resolved from 5,4,3,2, and 1ml concentration at 60 to 120 optimum separation time. Comparing the three different chemical demulsifiers, it showed that Tween 20 has highest resolving power followed by Tween 40 and the least Igepal co-720. From this result it could be deduced that the higher HLB, the higher the separation of water in emulsion. In addition, a ranking of the demulsifiers used showed that highest capacity demulsifier was the demulsifier with highest HLB.
Smart Well Technology Application in Deepwater Field Development
Authors: Ekebafe Abraham , Ogan Asitonka
Published: August 2012

A Field development plan has been completed for a deepwater field located in gulf of guinea in water depth of around 1100 - 1400m offshore. The field is a confined turbidite channel system with some incised canyons and meandering channel complexes.

The stacked nature of some of the reservoirs lends itself to combinations of drainage points. This can be harnessed to - reduce the well count by accessing multiple sands in one wellbore, accelerate production, and improve ultimate recovery from better reservoir management and/or development of reserves which cannot bear the cost of a dedicated conventional well.

Smart well technology has been deployed in the field development plan to facilitate the realizations of these advantages and hence make the project economics more robust.

In applying the technology, an integrated approach has been adopted all through the reservoir modelling, well planning and completion design sessions to ensure feasibility from the onset. A multi-disciplinary team and tools were fully deployed to ensure maximum gain realized in the smart well technology application.

Based on the work done so far, the following justifies the appropriateness of the technology for the field:

Smart wells overall value is in reducing the well count and overall CAPEX whilst maintaining the UR – Well count reduction by ∼20%. Well and reservoir management (WRM) Facilitation – Additional 10% to be gained from WRM via smart field implementation of appropriate level of smartness.

This paper discusses the integrated approach and the tools that facilitated the process.
Well Performance Optimization Using Experimental Design Approach
Authors: Okenyi K. C , Emeka Omeke James
Published: August 2012

The production rate of a well is a functional relationship of system parameter, such as tubing internal diameter, gas/oil ratio (GOR), wellhead pressure, permeability, and skin among others. A sensitivity analysis is done by performance software to obtain the optimum production flow rate. Conventional method accomplished this by sequential optimization. Owing to its computationally expensive and time consuming nature, the need to determine the most profitable well design configuration while considering a number of system parameters simultaneously becomes very important. This procedure is called Multivariate optimization and of interest in this paper.

A preliminary investigation of factors affecting the well's production rate was done. An eleven variable Plackett-Burman design approach was used to screen the main effect of both reservoir and tubing flow variables. Pareto chart was plotted to highlight the heavy hitters.

A D-optimal design was also applied to minimize the volume of the confidence ellipsoid for the coefficient and provides the most accurate estimates of the model coefficients. A fully quadratic response surface was developed. Graphical analysis where used to show the optimum points as well as the optimum production rate. This model provides a tool for preliminary estimates of optimum production rate simultaneously with the effects of other variables.
Geocentrism and Multinational Strategy: Case Study of Upstream Oil and Gas Industry in Nigeria
Authors: Adedipe Adeleke
Published: August 2012

The relationship between geocentrism and multinational strategy is non-definitive because of the difference of opinion amongst researchers however there is a paucity of existing work on the subject matter with respect to the upstream oil and gas industry. This current work is a case study approach to investigate the relationship between geocentrism and multinational strategy in two upstream oil and gas companies in Nigeria and the impact of the environmental dimensions (strategic, national and organizational) in the management of their subsidiaries.

This work is exploratory and utilizes existing constructs on multinational strategy, organizational design and index of geocentric orientation and data obtained from the survey of senior managers in the multinational companies. It reveals differences in the manner of correlation between geocentric orientation and the four corporate strategy variables or the four organization design variables for both companies. It indicates one of the two companies has an ethnocentric orientation, or can at best be classified as involved in enclave geocentrism, and thus signifying that a transnational company need not have a geocentric orientation. Furthermore it substantiates the impact of the strategic, organizational and national environmental dimensions in the management of foreign subsidiaries while indicating evidence of differences between espoused strategies and strategies-in-use in managing the Nigerian subsidiaries.
Concept of well design: NPT on drillers table – An Eco - Geomechanical Model for borehole stability management
Authors: Bassey Akong , Dosunmu Adewale , Alabi Tunde , Friday Otutu , Nnorom Grace
Published: August 2012

Mitigating drilling hazards ‘balancing drilling risks against the optimum well design while preparing for unplanned drilling events ‘has been a challenge to cost-effective well construction for decades. The pore pressure/formation fracture gradient balancing challenges mixed with the unexpected encounters with shallow flows, unstable formations, overpressure formations and depleted formations makes AFE (authorization for expenditures) goals dim. Excessive use of loss circulation pills and traditional contingency liners drive well costs up and jeopardize reaching total depth (TD) with an effective completion. A drilling hazard remediation solution could be as simple as using that planned contingency liner or using ddrrill-in casing to fight sloughing formations (McLean 1990). However, the use of conventional soolid expandable drilling liners can drive excessive risks into the well and even cause a costly sidetracking of the well on the drillers table. NPT in operations within areas of gulf of Guinea, gulf of Mexico and North sea have been successful due to absence of subsurface well integrity, lack of offset well information and economics. In view of this an Eco - geomechanical tool (GECDrill™) has been developed to handle the uncertainties created as a result of subsurface anomalies during well operations. Borehole drilling arises from the observation that an experienced driller can develop a good "feel" for the nature of formation being drilled. It should therefore be possible to establish an Eco - geomechanical tool (GECDrill™) to derive formation properties, subsurface geomechanical elements and cost indicators for economic evaluation through certain correlations. To minimize the NPT on drillers table, the Eco – geomechanical tool was developed based on realistic stress models coupled with linear elastic theorem and an economic risk assessment tool using a Monte Carlos bi-coupling strategy to evaluate the level and degree of NPT incurred while drilling in all fault scenarios.
A Simple Method to Estimate the Maximum Liquid Production Rate using Plunger Lift System in Wells
Authors: Bahadori Alireza
Published: August 2012

Plunger Lift is a cyclic method of artificial lift that uses a plunger to establish an interface between the liquid accumulated in the production tubing and the reservoir or annulus gas pressure that will be used to lift the fluid in wells. In this work, the maximum possible liquid production rate that plunger lift will tolerate for a given depth and tubing size has been placed on a quantitative basis by means of simple equations obtained from correlations of field data. The predictive tool developed in this study can be of immense practical value for petroleum engineers to have a quick check on the maximum possible liquid production rate that plunger lift will tolerate for a given well depth and tubing size at various wells without opting for any expensive field trials. In particular, petroleum and production engineers would find the proposed method to be user-friendly with transparent calculations involving no complex expressions.
Modern Magnetic Resonance Saturation Profile Data Accurately Quantify Fluid Volumes and Distribution in Tough Logging Conditions: Case Study from Niger Delta
Authors: Martey Amarquaye , Otevwemerhuere Joseph , Cavalleri Chiara
Published: August 2012

Future energy sources will come from their discovery by accepting more risk in exploration under tough drilling and logging conditions. In many fields in Nigeria, determination of producible oil and gas and in situ reserve volumes has proved too difficult for conventional, old vintage, logging suites. The complex mineralogy, presence of thin shale laminations and grain size variations within the sand bodies and very low and variable formation water salinity, require the use of advanced logging and conveyance technologies for accurate reservoir evaluation.

Advanced magnetic resonance wireline measurements provide a solution to evaluate reservoir quality and hydrocarbon systems potential. This technology is able to reveal a multitude of reservoir and wellbore properties supported by innovative signal processing and interpretation capabilities. This enables capturing essential information for multiple applications providing formation evaluation solutions unaffected by well deviations and borehole rugosity.

Continuous fluid characterization at multiple depths of investigation in a single logging pass from the advanced NMR tool resulted in correctly identifying the types and volumes of the various reservoir fluids and their contact levels.

The case study presented in the paper demonstrates the benefit of using advanced magnetic resonance in complex formation and in tough logging conditions where conventional measurements were inadequate. A major challenge in these reservoirs was the identification of the fluids contact, which was masked by poor resistivity contrast between oil and fresh formation water. In addition, the poor borehole conditions, severe enlargement and high rugosity, made it impracticable to successfully complete a planned wireline formation testing program.

The excellent data quality and reliability of the advanced magnetic resonance answer product despite the near wellbore damage and invasion effects proved that advanced magnetic resonance is a practical choice to provide accurate hydrocarbon volumes and in-situ fluid analysis to complement or fill the gaps in petrophysical and fluid sampling program in challenging complex and rugose borehole.
Modeling Approach for Niger-Delta Oil Formation Volume Factor Prediction Using Artificial Neural Network
Authors: Ikiensikimama S. S , Azubuike I. I.
Published: August 2012

Reservoir fluid properties are very important in reservoir engineering computations such as material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, this property should be obtained from actual measurements. Quite often, this measurement is either not available, or very costly to obtain. In such cases, empirically derived correlations are used in the prediction of this property. This work focuses on the use an artificial neural network (ANN) to address the inaccuracy of empirical correlations used for predicting oil formation volume factor. In this modeling approach 802 data set collected from the Niger Delta Region of Nigeria was used. The data set was randomly divided into three parts of which 60% was used for training, 20% for validation, and 20% for testing. Both quantitative and qualitative assessments were employed to evaluate the accuracy of the new Artificial Neural Network to the existing empirical correlations. The ANN model outperformed the existing empirical correlations by the statistical parameters used with a lowest rank of 0.855 and better performance plot.