bluuebunny/crossref_metadata_2025 huggingface dataset:
A Three-Dimensional Numerical Simulator for Expansion-Drive Reservoirs
Authors: Dele Ismaila. N. , Igbokoyi Alpheus. O. , Babalola Kola
Published: July 2014

Regime-specific numerical solutions are valuable in studying the behaviour of reservoir processes both for practical field management and for benchmarking the success of analytical solutions within the regime of interest. In this work, a three-dimensional numerical reservoir simulator is developed for expansion-drive reservoirs. The governing equation is discretized using finite difference approach, method of conjugate gradient with the aid of MATLAB program is used to solve the resulting system of linear equations to obtain cell pressure at every time step. Cumulative production is computed as sum of expansion from each cell and oil production rate is determined until bubble point pressure is reached. The average reservoir pressure is determined as a weighted average based on the stock tank oil that is left in the reservoir, and finally the recovery factor at the bubble point pressure is computed.

Contour plots, with colour map to ease the user's assimilation and interpretation of the simulator results, of reservoir pressure depletion with time were generated for different number of finite-difference grid blocks. The results indicate that the more the number of grid blocks used, the more accurate the numerical solution and the more detailed the description of the reservoir fluid distribution. The plot of average reservoir pressure against time shows a rapid decline in the average reservoir pressure due to the negligible compressibility associated with rock and liquid expansion-drive reservoirs. The estimated oil cumulative production of 236MSTB was recovered in 1180days up to the bubble point using the developed simulator. Furthermore, sensitivity analysis was performed to investigate the impact of key reservoir parameters on the average reservoir pressure. This work can be used to understand depletion in undersaturated reservoirs both for commercial field management and for validating new analytical solutions.
Estimation of Anhydrous Oil Density for Accurate Multiphase Flow Measurement: A Comparative Case Study
Authors: Mmata Bella , Onyekonwu Mike
Published: July 2014

The anhydrous oil density at flow line conditions is a key input parameter needed for accurate measurement of volumetric flow rates of the individual phases in a multiphase production stream (as in Coriolis multiphase flow meters). Accurate multiphase flow measurement in turn enables proper well and reservoir management, production optimization, fiscal allocation, unitization, volume record and custody transfer at pipeline station or port terminals.

Laboratory experiment provides the most accurate method of evaluating the value of the anhydrous oil density. However, whenever direct laboratory measurements are lacking, empirical correlations can be used to estimate this oil density at prevailing flow line temperature and pressure.

This paper compares experimentally measured oil densities of nine flow line samples from some offshore wells in the Niger Delta region with oil densities obtained from four different correlations. The Katz and the Standing correlations which have limited data input yielded root mean square errors (RMSE) of 2.9% and 3.1% respectively, while two other correlations based on composition namely the Standing-Katz and Alani-Kennedy correlations yielded higher RMSE values of 8.6% and 10.8% respectively. The use of the Katz correlation is therefore suggested in the absence of experimentally measured oil densities at flow line conditions for reservoir fluids with similar properties as those which were studied.
Z Factor: Implicit Correlation, Convergence Problem and Pseudo-Reduced Compressibility
Authors: Kareem Lateef A
Published: July 2014

Compressibility factor (z-factor) of gasses is a thermodynamic property used to account for the deviation of real gas deviation from the ideal gas behavior. The best correlations for this factor given by Hall and Yarborough, Dranchuk & Abou-Kassem and Dranchuk, Purvis & Robinson are based on nonlinear equation of state requiring iterative solution.

It is not uncommon for nonlinear equations to have multiple roots, hence, Newton-Raphson often fail to converge or converges on the undesired root of these equations. This unstable behavior of iterative procedure requires that the initial guess is set close to the desired root to ensure convergence.

Here we examine the residual equations of the reduced densities of these correlations and set the criteria for the determination of the initial guess as function of the reduced temperature (1.05 ≤ Tpr ≤ 3) and pressure (0.2 ≤ Ppr ≤ 15), we retuned the coefficients using 5940 experimental data points from Handbook of Natural Gas Engineering and also derived the reduced compressibility equation based on these three correlations.
Engineered Approach Enables Successful Cementation of 4.5-in. Liner in a Hostile Down-Hole Environment
Authors: Ilesanmi Oluwagbemiga , Hilal Bashar , Gill Stephen
Published: July 2014

A 4 ½-in. liner cementation in a high-profile exploratory well was executed for a major onshore operator in UAE in a challenging environment.

More recently, a 4 ½-in. liner was cemented in a 6-in. vertical hole at a depth of 11,930 ft across the Arab and Diyab formations. Corrosive substances, including high concentrations of CO2 & H2S, were present in this well. The H2S level was expected to be as high as 340,000 ppm and the CO2 around 12,000,000 ppm. Adding to the complexity, the BHT of the well was 345 deg. F.

This extremely challenging and hostile down-hole environment was addressed by using a “fit for purpose” CO2/H2S-resistant cement system designed to isolate the targeted zone and ensure the integrity of the wellbore for the entire life of the well.

The margin between the open-hole fracture pressure and the maximum predicted ECD in the wellbore during the job was extremely tight, and losses were to be expected. In an attempt to offset this, a proprietary lost circulation spacer was pumped ahead of the CO2/H2S-resistant cement system to mitigate the potential for losses and control any additional induced losses while cementing. The spacer had the dual capability of maximizing hole cleaning and strengthening the formation face in the wellbore ahead of the heavy 16.7 ppg (125 pcf) cement slurry.

Software was used to optimize the ECD, centralizer spacing and drag/torque calculations based on the available data received from the customer. In addition, temperature modeling was performed to improve the prediction of wellbore and formation temperatures during fluid circulation and cement slurry placement.

This paper will address the procedures followed from the slurry and spacer design phases through to the placement of the cement slurry that ultimately led to the successful execution of the job.

From an operational and technical standpoint the job was considered a success in that it met all the objectives identified and defined during the well planning stage. The well was logged approximately 48 hours after the cementing operation and the cement bond log was judged to be good and was accepted by the operator.
Evaluation of Rice Husk as Fluid Loss Control Additive in Water-Based Drilling Mud
Authors: Okon Anietie N. , Udoh Francis D. , Bassey Perpetua G.
Published: July 2014

Organic polymers are commonly used to control filtrate loss in water-based drilling fluids both in circulating and non-circulating periods during drilling operations. In Nigeria, the over dependence on these polymers to achieve this function of drilling fluid is worrisome on the overall well drilling cost. Therefore, a substitute for these polymers with locally available materials is indispensable. In lieu of this fact, an agro by-product, rice husk was evaluated as a possible filtration loss control additive in water-based drilling mud and the results compared with sodium carboxymethyl cellulose (CMC) and polyanionic cellulose (PAC) using static fluid loss measurement approach. The results obtained depict that with a concentration of 20g content of rice husk to 350mL mud (about 20lb/bbl) there was a decrease of 64.89% in fluid loss compared to 62.77% and 59.57% for CMC and PAC respectively at a content of 10g per 350mL mud. Additionally, filter cake thickness measurement from the husk showed a decrease of 3.03% and 8.57% respectively when compared to CMC and PAC. Thus, exploitation of rice husk as fluid loss control additive in water-based mud would be a welcome development in the oil and gas industry since its characteristics of high resistance to water penetration and thermal stability would be applicable to deep wells where high temperature is anticipated since CMC and PAC temperatures degrade at this condition.
Nanocompletions Versus Intelligent Well Completions, Investigating the Future of Nanotechnology in Well Completions - A Case Study
Authors: Opeoluwa Olawale
Published: July 2014

The oil and gas industry continues to face different challenges in the field of exploration and production. From field exploration to exploitation, including survey methods, drilling techniques, completion systems, production to reservoir monitoring, operations and processes are not only cost intensive but also technologically demanding. Hence, the potential for applications of nanotechnology in the Oil and Gas Industry is huge. However, despite several research efforts, few “nano-breakthroughs” have been achieved in the industry due, in part, to its high cost of application. This paper investigates the application of a specific nanotechnology- polymer supported nano-particles (PSNPs) in production tubing/completions of stacked reservoirs and compares this to Intelligent Well Completions (IWC) using a Niger Delta Case Study- Well X. It also employs the novel idea: nanocompletions- the integration or, better still, the adaptation of known applications of potentially viable nanostructures to the development of the major components and functionality of well completion systems/options. The lower costs, high sensitivity and fast response speeds achievable with PSNPs make them viable alternatives to IWCs, and most recently developed completions systems in the independent monitoring of flow properties and downhole data gathering for future field development plans and precise reservoir modelling. Cost benefit analysis of the proposed nanocompletions in solving challenges of downhole measurements and Intelligent Well Completions is presented. This paper shows that the application of nanotechnology in monitoring Well X and by inference any other well, in similar geological zones, can provide higher efficiencies and cost- savings.
Statistical Characterization of Performance of Biopolymer Drill-In Fluid for Different Rheological Models
Authors: Owusu M. , Enty G. S. , Osei-Twum A.
Published: July 2014

Appropriate selection of rheological models is important for hydraulic calculations of pressure loss prediction and hole cleaning efficiency of drilling fluids. Power law, Bingham-Plastic Herschel-Bulkley models are the conventional fluid models used in the oilfield. However, there are other models that have been proposed in literature which are under / or not utilized in the petroleum industry. The primary objective of this study is to recommend a rheological model that best-fits the rheological behaviour of xanthan gum based biopolymer drill-in fluids for hydraulic evaluations. Ten rheological models were evaluated in this study. These rheological models have been posed deterministically and due to the unrealistic nature these were replaced by statistical models, by adding an error (disturbance) term and making suitable assumptions about them. Rheological model parameters were estimated by least-square regression method. Models like Sisko and modified Sisko which are not conventional models in oil industry gave a good fit. Modified Sisko model which is a four parameter rheological model was selected as the best-fit model since it produced the least residual mean square. There is 95% certainty that the true best-fit curve lies within the confidence band of this function of interest.
Effects of Both Wellbore and Reservoir Properties on Dimensionless Pressure and Dimensionless Pressure Derivative Distribution of a Horizontal Well in a Reservoir Subject to Bottom Water, Gas Cap and Single Edge Water Drive Mechanisms
Authors: Edobhiye O. , Adewole E. S
Published: July 2014

This paper investigates the effects of both wellbore and reservoir properties on dimensionless pressure and dimensionless pressure derivatives of a horizontal well in a reservoir subject to bottom water, gas cap and single edge water drive mechanisms. Properties considered in this paper include dimensionless reservoir thickness, dimensionless well stand-off, dimensionless wellbore radius, dimensionless well length, infinite conductivity and uniform flux completions. The effects of rectangular and square reservoir geometries were also considered. New procedures were developed for prolonging the period of clean oil production. In order to achieve these objectives, Source and Green's function together with the Newman product rule were utilized.

Results show that dimensionless pressure increases with reservoir thickness. Dimensionless well stand-off did not show any effect on dimensionless pressure and its derivative. Dimensionless wellbore radius and dimensionless well length were found to be inversely related to dimensionless pressure. Infinite conductivity and uniform flux completions did not affect dimensionless pressure.

The information presented in this paper will help in the correct design and completion of wells in the reservoir and points of perforation locations for prolonged clean oil production.
Field Case Histories: Countering Lost Circulation with Monofilament Polypropylene Fiber
Authors: Mofunlewi Samuel S. , Okeke Chinyere , Bankole Abidemi , Ighodaro Osaze
Published: July 2014

One of the most time consuming and cost inflating events in drilling operations is loss of circulation. It has been globally estimated to cost the drilling industry more than $1billion annually in rig time, materials and other financial resources. Lost circulation is the total or partial loss of drilling fluids or cement slurries into highly permeable zones, cavernous formations, or natural/induced fractures during drilling or cementing operations. Lost circulation usually occurs when the hydrostatic head pressure of the column of drilling fluid exceeds the formation pressure.

This expensive problem is typically minimized or prevented by blending additives into the mud or cement system. One such additive is a monofilament polypropylene fiber. The fiber is an inert fibrous material that forms a network across the loss zone bridging and sealing the zones effectively.

The monofilament polypropylene fiber was proposed as an additive to a cementing system designed to counteract lost circulation issues that were expected while cementing two wells in the Niger Delta Basin in Nigeria. The loss in circulation was believed to be caused by natural fracture systems and high permeability within the zones to be cemented. The additive was first tested in the laboratory and determined to be efficient at countering the type of losses expected, and then was used in the field.

This paper will focus on the laboratory testing and the field application of the monofilament polypropylene fiber in two Niger Delta wells. The paper will include a thorough description of prior attempts to solve the lost circulation problem and results of using the new material.
Inclusion of Well Schedule and Project Life in Well Placement Optimization
Authors: Awotunde Abeeb A.
Published: July 2014

Well placement optimization plays an essential role in reservoir management. When wells are placed in optimum positions in the reservoir and operated at optimum rates or bottomhole pressures, the financial return on investment is expected to be high. In a highly heterogeneous reservoir, placing the wells in appropriate positions, although very challenging, can improve the profitability of investment significantly. Also, operating the wells under appropriate controls can enhance the viability of the project. One challenge with well placement, however, is how to simultaneously optimize well locations, well controls, well types, well schedules and project life cycle. Many works addressing the issue of well placement optimization often fix the project life and also assume that the wells were drilled at the beginning of the project. It is well known that all wells cannot be drilled all at the beginning of the project due to manpower and facility constraints, even if that scenario is the optimal choice for high net present value of the project.

In this work, we present an optimization framework that simultaneously finds the optimal number of wells, their types, locations, controls, well schedules and the optimal project life cycle. The method is an extension of our previous work in which all the above except well schedules and project life cycle have been determined using global optimization strategy. We included an additional variable that represents the project life in the list of optimization parameters and one variable per well to represent the fractional time at which the well is to be drilled, completed and put on production or injection. This fractional time is a fraction of the total project life and each well has its own fractional time. This means that wells will not be drilled all at the same time during the project life. To ensure that too many wells are not scheduled for drilling/commissioning during the same year, we adopted the penalty approach to enforce a set of inequality constraints that ensure that the number of wells drilled and put on operation in any particular year is not more than a predetermined number. Differential Evolution was used as the global optimizer to solve the problem. Results show that the method is able to yield high net present value corresponding to the estimated set of parameters including well schedules and project life cycle.
Integrated Model-Based Approach to Drilling Project Management
Authors: Omosebi O. , Osisanya S. O. , Ahmed R.
Published: July 2014

Drilling operations account for over 80% of the total cost of a well and this cost will continue to increase rapidly as the petroleum industry moves deeper offshore to explore additional reserves. In many regions around the world especially the Gulf of Mexico, Gulf of Guinea and North Sea (i.e. The Golden Triangle), daily operational cost of an offshore rig range from $1 million to $1.5 million. This high cost, as well as increasing concern to exceed stakeholders expectation, has underlined the necessity for sound project management to ensure that wells are drilled at lowest possible costs since the major objective in all drilling operations is to safely drill useable holes at minimized cost. Most often, only technical aspects of rig operations are thought to influence the number of days spent on location. In a more practical sense, however, both technical and non-technical issues control the success of rig operations; hence the need for a holistic approach for effective project delivery.

In this paper, a comprehensive and integrated model-based approach is proposed for managing drilling projects. This technique is based on project management body of knowledge and it emphasizes both technical and non-technical factors that influence successful drilling operations. Using this method, a dynamic well plan can be developed which can always be updated with current information obtained as drilling progresses. This scheme facilitates real-time documentation of lessons learnt which will aid planning and implementation of future drilling programs. Furthermore, project performance can easily be tracked on the basis of triple constraints of time; scope and approved budget since high-quality drilling management practice involve effective monitoring and control of these constraints. Collaborative engagement of drilling contractor, operating and service company representatives throughout the project phases is indispensable for full implementation of the proposed system. This scheme ensures development of detailed and dynamic authorization for expenditure (AFE) that accounts for non-technical project constraints. This paper is most applicable in management and systems technical category.
Impact of Radioactive Sources on the Environment: A Case Study of an Abandoned Oil Well in the Niger Delta
Authors: Dosunmu Adewale , Odagme B. S , Kamal K.
Published: July 2014

Crude oil exploration involves various operational processes and practices such as remote sensing methods of mapping. Moreover, radioactive detectors and explosives associated with seismic exploration, drilling and production equipment, LWD, MWD, uncontrollable wellbore instability, stuck pipe and loss of logging tools in hole issues leading to sidetracking, abandonment activities which leaves an impact on the environment. In this work, the radiological hazard indices in an abandoned oil well of Niger Delta was evaluated in the soil/sediment and water samples of the area to ascertain the impacts on the area and possible solutions were recommended. For soil samples, the mean value of Annual Gonadal Equivalent Dose (AGED) of the five locations was 665.25±65.07mSvy−1 and that for Annual Effective Dose Equivalent (AEDE) (Outdoor and Indoor) were 115.75±11.86μSvy−1 and 463.02±44.44μSvy−1 respectively. The Excess Lifetime Cancer Risk mean value was (0.41±0.04) × 103. The mean values for Representative gamma index, Iγ, the External Hazard index, Hex, and the Internal Hazard Index, Hin, were 0.62±0.01, 0.53±0.06 and 0.66±0.02 respectively. The radiation indices for the water at the abandoned well site, and many locations in the village were also calculated. For soil/sediment samples, the mean value for these indices were above the permissible value which showed radiological elevation in the areas. The radiological elevation from the percentage risk analysis signifies a radiological burden on the people and the environment of these areas and there is the possibility of developing cancer due to exposure to radiation before the age of 70 years for the people living in the areas.
Developing a Robust Emergency Pipeline Repair System in Nigeria
Authors: Iyede Efemena , Akinola Mobolaji
Published: July 2014

Pipelines form the backbone of oil and gas production, and are no doubt, one of the safest and most economical means of oil and gas transportation today. Consequently, increased oil and gas production means significant increase in the application of long distance pipelines for onshore and offshore oil and gas transportation.

In sub-saharan Africa, the pipeline industry is gaining momentum as more investment is planned for the oil and gas sector over the next few years. Statistics have shown that more investments by indigenous and foreign companies including government partnerships have been put in place towards developing pipeline infrastructures in Nigeria. With reports of approximately 12,000km of total pipeline length currently installed in Nigeria, forecasts predict a construction of up to 2,000km more in the next 5 years to boost domestic gas supply and other petrochemical infrastructures. [Pipeline and Gas Journal, Vol 239 No.1, 2012]

From an economic standpoint, pipeline assets can be categorized into critical and non-critical pipelines, based on the level of impact they have on the Operators' production figures. Critical Pipelines are those that generate important loss of production, and financial risk to the Operator, should operation be interrupted for a significantly long time. The failure of such pipelines can also be a disaster in terms of environmental contamination resulting from leakages or oil spillage. This therefore means, pipeline Operators need to adequately prepare in advance for emergency failures as they can be very dramatic with associated high production losses and environmental damage.

The onus lies on pipeline operators to put in place a robust strategy ensuring preparedness for "unexpected" failures. Therefore, an Emergency Pipeline Repairs System (EPRS) becomes imperative in the Operational Management System.

This paper focuses on good EPRS practice, key components of a robust EPRS strategy; some pipeline defects and emergency repair options, and concludes with a case study of EPRS mobilization in Nigeria showing major lessons learnt.
Application of Time Series Analysis to Predict Reservoir Production Performance
Authors: Olominu Oluwafemi , Sulaimon Aliyu A.
Published: July 2014

Decline curve analysis (DCA), material balance (MB) and numerical simulation are used to predict reservoir performance. However, these methods have peculiar strengths and limitations. While some are based on analytical observations and theories others are purely stochastic. The objective of this study was to investigate the applicability of Time Series analysis to predict oil cumulative production as a measure of reservoir performance. The Box Jenkins method of Time Series analysis utilizing the Autoregressive Integrated Moving Average (ARIMA) models was used to predict and analyse oil cumulative production of wells and reservoirs. The process involves a robust transformation of production datasets into time series. A best fitting model was chosen using maximum absolute deviations as a measure of fit. Predictions of the ARIMA model were validated with historical data and its performance was compared with Decline Curve analysis (DCA).The coefficient of each model was optimized using the simplex optimization technique.

The results show that ARIMA (1,1,0) model gives the best match with actual cumulative oil production data. The model had the least maximum deviation of 4.24% compared to 178.95%, 182.32% and 24.45% for ARIMA (1,0,0), ARIMA (2,0,0) AND ARIMA (1,2,0) respectively after predicting for 900 days. Analysis of results after 1097 days of production also shows that the ARIMA (1,1,0) predicts better than the DCA method. The maximum deviation for both ARIMA and DCA were 1.81% and 12.79% respectively. The best model coefficients fall between 1.99 and 1.9999999. A model coefficient too high or too low will definitely lead to erroneous predictions. This study has shown that ARIMA (1,1,0) can be used to model and predict reservoir/well cumulative oil production accurately for short to mid-long term periods. Furthermore, the model performs better than the DCA for medium to mid-long term predictions. The accuracy of the model can be improved as more data become available for history matching to further refine the model coefficients. A model coefficient of 1.995 is recommended when few data are available.
A Laboratory Study of ASP Flooding on Mixed Wettability for Heavy oil Recovery Using Gum Arabic as a Polymer
Authors: Avwioroko Jerome , Taiwo Oluwaseun , Mohammed Ismail , Dala Joshua , Olafuyi Olalekan
Published: July 2014

A Laboratory Study of ASP Flooding on Mixed Wettability for Heavy Oil Recovery Using Gum Arabic Polymer Alkaline-Surfactant-Polymer (ASP) flooding process offers a promising approach to recover the residual oil which often times is more than 50% of original oil in place.

This paper presents the summary of the laboratory studies on the effect of wettability on oil recovery of Alkaline/Surfactant/Polymer flooding using a Local Polymer – Gum Arabic which is vastly available in Nigeria. Engineering grade class IV glass beads were treated with chemicals to water-wet (WW) and oil-wet (OW) conditions. Different degrees of wettability were obtained by mixing the WW and OW glass beads in different ratio before each flooding experiment. The mixing ratio used were 100%WW and 0%OW; 75%WW and 25%OW; 50%WW and 50%OW; 25%WW and 75%OW; 0%WW and 100%OW. The displacement efficiency of Alkaline/Surfactant/Polymer flooding and Polymer flooding at the different wetting conditions was evaluated by laboratory coreflood experiments.

From the experimental result, it was also observed that oil recovery increases as formation becomes more strongly water wet. The experiment results indicate that the displacement efficiency of water floods and ASP flooding is markedly affected by the wettability of the core. The wettability is one of the important factors to determine the oil recovery of water and ASP flooding. Water-wet and oil-wet conditions are favourable to obtain high enhanced oil recovery for ASP flooding using locally available Gum Arabic.
Application of Mechanical Cleaning Device: Hole Cleaning Tubulars, to Improve Hole Cleaning
Authors: Nwagu Chike , Awobadejo Toyin , Gaskin Keith
Published: July 2014

Efficient removal of drilled cuttings from a wellbore during the drilling process is critical to the success of any drilling operation. The negative consequences of inefficient hole cleaning can range from the occurrence of significant Non Productive Time due to time and resource consuming remedial operations, to the potential sticking of the drilling BHA and potential loss of the entire wellbore. These can carry very significant financial consequences ranging from tens of thousands to millions of dollars (USD).

While hydraulic hole cleaning during the drilling of vertical wells is a relatively straight-forward matter, the cleaning of deviated wellbores presents entirely different challenges which have been well documented. The Illah field, located offshore the Niger Delta region of Nigeria, presents specific challenges which result in the requirement for significantly deviated wells, which present numerous hole cleaning difficulties. Some of these challenges include but are not limited to: Vertically stacked and laterally offset objective reservoirs.Multiple completion objectives and strategies per wellbore requiring complex well designs.

It is a well-documented fact that cuttings removal in inclined wellbores becomes more difficult as the hole inclination increases. In the medium to horizontal deviation scenarios the tendency for cuttings to accumulate into "beds" comes into play and these cuttings beds will increase in severity in the critical angle range depending on other factors such as particle/cutting size. Some other factors which could contribute to the accumulation of cuttings in inclined boreholes include; drilling fluid rheology and density, flow rates, drill string RPM and mechanical wellbore instability.

This paper which is a case study of drilled wells in the Illah field, concentrates on the effects of the application of a mechanical cleaning device; Hole Cleaning Tubulars, to the problem of down hole accumulated drilled cuttings whilst drilling deviated wells.
Championing Nigerian Content Development Initiative through Hydrocarbon Maturation Studies: Project Management Lessons
Authors: Ndukwe Reginald , Cookey Mina , Nworie Ejiuwa
Published: July 2014

The Shell Petroleum Development Company of Nigeria Limited (SPDC) and its Joint Venture partners have consistently demonstrated leadership in developing Nigerian Content in the oil and gas industry through its Nigerian Content Development (NCD) initiative. This is further demonstrated by the landmark award of four oil and gas maturation services contracts for Petroleum Engineering studies to indigenous contractors. The contract award aimed at achieving: (1) Acceleration of hydrocarbon maturation and unlock huge resource portfolio/potential available in the fields of study; (2) Growth of hydrocarbon maturation capacity and capability of indigenous contractors in line with NCD aspirations of the Nigerian Government and (3) Enhancement of in-country capability in managing Petroleum Engineering studies delivery using local vendors.

The work scope included sub-surface evaluation of work elements in selected fields / reservoirs (up to well head), leading to feasibility reports. The work plan required the vendors to work from their locations and use their software and hardware, and local manpower resources to deliver the projects in a period of three years. The SPDC support team was available to (a) Coordinate delivery of the project (working in collaboration with the vendors' leadership teams to achieve this); (b) Provide technical "peer-assist" to the vendors (this is to enable the vendors to deliver quality results on time); (c) Deliver Wells and Facilities Engineering, Economics and Operations Readiness aspect of studies and (d) Integrate all works and produce feasibility reports.

The studies have progressed for about 18 months; with the project teams having made good progress; as well as encountering some challenges and risks which could impact project delivery, including: (1) High staff mobility among local vendors; (2) Staff technical competence; (3) Unrealistic contract bids; (4) Inadequate scoping of assurance requirements and (5) Project delivery within contract period. Mitigation plans for these challenges/risks are discussed herein, along with lessons learnt in the project management.
Improved Drilling Efficiency via Enhanced Water Based Mud in The Niger Delta
Authors: Falope F. D. , Orodu O. D. , Osayande I. , Uhunoma U.
Published: July 2014

This study focuses on latest advances in water based mud as a potential for the Niger Delta, its impact on drilling efficiencies and well productivity. Recently, New mud additives are been developed to enhance the rheology of water based mud to deliver the same characteristics and reliability of an oil based mud when considering the Niger Delta geology. Due to the challenges with Water Based Mud in respect to chemistry and suitability, Oil Based Mud (OBM) has become the main type of drilling fluid in deeper sections during drilling campaign in the Niger Delta. But the use of OBM as come with some challenges that has necessitated the further research and development of Water Based Mud rheology that can deliver the same results as OBM. Some of the challenges associated with the use of OBM include but not limited to high cost and management, contamination of OBM in the storage site during drilling activities, logistics complexity, environmental impact from spills and disposal, and impact on well productivity and reservoir management.

In countries such as Ghana, Columbia, Oman, Mexico, Enhanced WBM mud has been used and is still being used in drilling to deep depths (8000ft–10000ft) TVD in formations with similar geology with that of the Niger Delta. Sample wells will be reviewed from one of these regions for the project and they will be used to show the evolving new technologies and techniques in WBM rheology formulation.

This study is channeled to label the engineered properties of the mud, mud composition, its effects on drilling efficiency and well productivity, challenges encountered, the concept for an enhancement, added advantage in comparison to OBM, comparative cost advantage. It was discovered that Enhanced WBM has an added advantage hence leading to a reduction in pollution trends in the Niger Delta and cost effectiveness. Other advantages include addressing to an extent the challenges encountered with WBM such as (inhibition, hydration and solids control) leading to an enhanced well productivity and ultimately affects the overall cost of well delivery.
Proven and Possible Petroleum Plays of the Eastern Niger Delta Basin, Nigeria
Authors: Anomneze David O.
Published: July 2014

As Nigerian operations expand into more challenging and costly operating environments, there is need for critical access to sound stratigraphic, depositional and reservoir facies models. The extraction of geomorphic insights and pattern recognition using predominantly 3D seismic data is a rapidly evolving discipline that facilitates the development of reservoir prediction models linked to significant plays. In this study a regional dataset which comprised of a merged 3D seismic volume, well logs, biostratigraphic, biofacies, paleobathymetry and core data from Eastern Niger Delta was interpreted and reviewed to show the overall structural, stratigraphic and architectural styles within the region to ensure that successes made in the past can be repeated and also make significant advances to ensure future exploration success. Hence, an added goal is to have a low-risk exploration workflow that is capable of correct prediction of reservoir rocks to be encountered in a new play and prospect. Three plays have been identified from this study: (1) Shelf Edge Deltas, (2) Pinch-Out Play and (3) Hanging Wall Play. Each play displays a unique morphology, seismic expression, structural configuration, migration pathway, seal integrity and reservoir dispersal pattern. These prediction models provide play based exploration targets for areas with similar depositional settings. The successful application of this technique serve to encourage exploration in the Niger Delta Basin by adopting strategies where seismic stratigraphy will be the most likely means to provide drilling targets to more independent operators.
West African Market Integration
Authors: Excel Ukpohor
Published: July 2014

With a landmass of about 5.1 million square kilometers and a community of 15 member states, Western Africa is one of the worlds most endowed regions with energy sources. The region holds about 13% of the total proven gas reserves in the world, with Nigeria accounting for almost all that figure with 185tcf.

While natural gas is fast becoming the worlds preferred choice of energy thus seeing an increase in its demand, the region is yet to fully harness the potential she possess in energy generation. West Africa still ranks amongst the regions with the lowest energy generation in the world. Major sources of energy are petroleum, natural gas and hydroelectricity and it is estimated that no more than 20 percent and in some countries as little as 5 percent of the populace have direct access to electricity. The figure falls to about 2 percent in the rural areas. This situation has become a major hindrance to the economic and technological growth of the region.

Thus, energy has become a major driver for regional integration in West Africa, which can assist many of her individual economies in overcoming the mismatch between energy demand and energy resource endowments. Furthermore, this can take advantage of economies of scale and help countries develop and gain access to low-cost energy to sustain future growth. Resource rich smaller economies would then export energy which can become engines of growth and development while larger economies energy imports may help postpone, reduce, or avoid capital investments in new production facilities and thereby overcome temporal cash flow problems.

To integrate the various economies of the region, the governments of the various countries have commenced a number of regional projects. The West African Gas Pipeline (WAGP) is a good example of regional energy market integration. It shows on the one hand achievements of government and regional institutions and the other, the willingness of international companies to invest in the regional market. The West African Power Pool is another regional project with the concept of integrating the national grids of the region member countries.

In this paper, the huge gas potential of the West Africa region will be highlighted and the impact of the gas production from the region on the global economy. The energy situation of the region will also be discussed with the various challenges detailed. The roles of natural gas in the various regional projects being executed will be listed with status update of these projects with particular emphasis on the West Africa Power Pool (WAPP) and the West Africa Gas Pipeline project. Various geopolitical influences will be discussed with major emphasis on polices that impact integration. Finally recommendations will be made on some key success factor that will promote rapid regional development in the face of the mounting challenges.
Resolution of Out of Zone Water Injection in Okan Field by Use of Material Balance Method
Authors: Olu Okpani , Adebayo Oguntona , Femi Afolayan , Segun Olonode
Published: July 2014

The Material Balance method is a good analytical tool for assessing and understanding energy balance and connectivity of reservoirs. This method was used to investigate the effect of water injection in a target reservoir and pressure response in the target reservoir and an adjacent reservoir in Okan field.

Water injection was initiated in two adjacent reservoirs (Reservoir "A" and Reservoir "B") in Okan Field in year 2002 with wells A1_Inj and B1_Inj respectively. Another water injector (Well A2_Inj) was completed in Reservoir "A" in year 2008 to provide further pressure support for the reservoir. Analysis showed that the water injection in Well A2_Inj was not providing pressure support to Reservoir "A" as expected. In addition an unexpected reservoir pressure increase was observed in Reservoir "B" from year 2008. It was suspected that Well A2_Inj was injecting out of zone and there was contemplation to cut-back water injection in the well and allocate the water injection to other injectors in the field.

Results

Material balance analysis was carried out by coupling Reservoir "A" and Reservoir "B". The following are the results of the study:
Mini-DST in a Gas Reservoir: Issues, Challenges and Benefits
Authors: Uwaga Anthony , Bardal Davoud , Ward Chris , Trim Melanie
Published: July 2014

Well testing during the drilling of a well using a Drill Stem Test (DST) tool is a well-established practice in the oil and gas industry. As the name suggests the well test is conducted using the drill stem with the DST tool replacing the drill bit. It is done in open or cased hole and the objective is to measure the pressure, permeability and productivity of the zone of interest. It also gives a measure of the damage done to the formation during the drilling process.

In the case of an oil reservoir oil is produced to surface during the DST operation and either collected in tanks or flared together with the associated gas. In the case of a gas-only reservoir the gas produced to surface is flared.

Some of the issues of carrying out a DST test are the high costs involved, limitations in acquiring detailed zone specific information instead of averaging over the well test length and the potentially negative impact on the environment from hydrocarbon flaring. It is to overcome these challenges that the industry looked for alternative well test approaches that can be more efficiently undertaken during drilling operations such as the Wireline Formation Test (WFT), also known as a mini-DST.

A mini-DST well test is carried out using a wireline tool and is conducted in open-hole. The well test involves isolating a zone of interest using packers with pressure and hydrocarbon flow rate readings captured using a single probe, a dual probe or a combination of single and dual probes. Unlike the DST it can be done over multiple zones, isolating one zone at a time and has an added advantage that all fluid flow takes place down-hole.

In reservoir intervals with good permeabilities and high production rates, the relatively high mobility of gas compared to oil will result in turbulent flow being observed in the wellbore thereby introducing ‘noise’ that will mask the sensing of pressure transients by the probe. This is not the case in mini-DST test as the production rates are quite low already. However, for a gas reservoir it is sensitive to the permeability-thickness (kh) product in the zone of interest, since higher kh and lower gas rates can result in a very small drawdown. Therefore pressure gauge sensitivity becomes a significant factor in the well test design for a mini-DST. With a typical gauge resolution of ca. 0.01 units there is, therefore, an inherent constraint to targeting primarily low kh flow zones. This can result in a trade-off when selecting reservoir units to test based on their permeability (k) and thickness (h).

This paper looks at some of the issues to be considered in the design and operation of a mini-DST well test for a gas reservoir and highlights key benefits that can be derived. It further discusses some of the operational challenges encountered during a case study.
Effective Field Development Management of a Gas Field in the Niger Delta
Authors: Egu Daniel Ikechukwu
Published: July 2014

Investment and operational planning of gas field development under severe uncertainties in gas reserves poses a major challenge in post parts of Eocene Niger Delta. Such uncertainties include the size of gas in the reservoir, the recovery factor, the required number of wells to be drilled, permeability variations and other criteria. Fekete "FAST" Evolution software was used to run a detailed sensitivity analysis of reservoir properties particularly permeability, in order to determine the number of wells to drill, recovery factor, net present value (NPV) and also the sales of gas produced per well, to effectively ensure maximum hydrocarbon recovery and a good return on investment without posing danger to the reservoir. Results however showed that in terms of recovery factor, scope three had a maximum recovery factor of about 73.61%, in terms of sales gas produced per well. It also had the highest sales gas production of about 10811.5M$, which will yield about 32434.4M$ for the three number of wells investigated as a result of a higher permeability. Also in terms of the net present value, scope one had the highest value of 110633.06M$, for the 12 numbers of wells investigated. It is recommended that since scope three had a better performance than the base case due to higher permeability value, a stimulation job may be carried out at the completion of the project to enhance the permeability of the reservoir, but the cost of carrying out the stimulation job should be considered and analyzed to ensure a good return on investment, before embarking on the decision.
Improved Deliverability Model for Horizontal and Multilateral Wells
Authors: Ulaeto U. W. , Onyekonwu M. , Ikiensikimama S.
Published: July 2014

A simple semi-analytical model was developed in this study to predict the productivity of horizontal oil wells. This model used the technique of coupling flow from a box-shaped drainage volume to that of the flow in the wellbore. Considerations were made for friction, acceleration, and fluid-inflow effects. Change in flow regime from laminar to turbulent was also taken into account to describe the flow in the wellbore. The reservoir-inflow model used in the productivity model for flow in the reservoir used a combination of 1D and 2D models and also considered varying skin along the wellbore to account for the heterogeneity of the near-wellbore region due to drilling-fluid invasion into the formation. In addition, reservoir-permeability anisotropy and convergence of flow to the wellbore were considered in the inflow model. Comparison of this model with three well known models using field data reveals that the proposed deliverability model is more accurate with a 4% error. The existing models gave greater errors. The accuracy of this new model can be attributed to more realistic modeling of the reservoir and wellbore.