bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling Crude Oil Production Outlook: A Case Study of the Oil and Gas Industry in Nigeria
Authors: Kingsley-Akpara Chiamaka , Iledare Omowunmi O.
Published: July 2014

In the past four decades, Nigeria has made impact on the global oil and gas exploration and production industry. As one of the lead exporters of crude oil and natural gas in Africa, an oil production model which tracks oil exploitation process is imperative to facilitate good national economic planning and industry strategy. The impact of technological advancement, policy incentives and economics can be estimated from such petroleum production model.

This paper reviews historical crude oil production in Nigeria; develops an empirical model to describe and explain the competing factors underlying its production patterns. The production model equations are formulated; with a non-linear curve fitting method to estimate the Hubbert's model parameters for Nigeria. The model is used to forecast future production outlook for Nigeria.

At the currently estimated reserves of 37.2 billion barrels, the model results suggest that production rate should have peaked at 2.70 MMSTB/D in year 2010, and forecasted that the estimated ultimate recovery, at year end 2050, will be 65 billion barrels (~ cumulative production of 31.25 billion barrels up till 2012 plus current proven reserves of 37.2 billion barrels). It suggests that the nation had just produced 50% of its currently estimated proved reserves. The Hubbert model was accurate for forecasting US crude oil production, but its strict symmetry has received criticism from experts (Lynch, 2002) (Cavallow, 2004) (Iledare, 2000) who believe that the model underestimates future production which our experiences also confirm. We specified the nature of the errors which resulted in considerable deviations of production trends from the Hubbert model.

We suggest however, alternative model for analysing the exploitation process in Nigeria in the form of successive curve re-fitting of Hubbert model to new production data from time to time to check the effect of new technology, economics or policy implementation on Nigeria's crude oil production.
Maximizing Recovery in a Lobate Mature Water-flooded Reservoir
Authors: Jeboda Olatunji , Ambastha Anil , Eme Vincent , Ogugua Emeka
Published: July 2014

Reservoir E is an offshore saturated black-oil reservoir with three lobes, initially thought of as independent reservoirs, but later seen as lobes of same reservoir with acquisition of more pressure data. It started production in 1968, but was shut-in in 1985 due to declining pressure. After the onset of waterflood in 1992, pressure data showed the reservoir behaving like two pressure tanks aerially (Main and Horn Area).

The main area showed good pressure response from water-flooding but limited response was observed in the horn area. The challenge has been how to improve the current reservoir performance given the availability of reserves especially in the horn area which is pressure challenged.

This paper describes a three-dimensional, three-phase, black-oil simulation of Reservoir E. The purpose of this study was to investigate and identify the optimal operating scheme for maximizing recovery in this reservoir.
Improving the Accuracy of Gas Measurements/ Gas Accounting in the Oil and Gas Industry – Pitfalls and Remedies A Case Study of an Onshore Field in Nigeria
Authors: Ibeh Stanley , Obah Boniface , Nnakaihe Stephen , Umeh Valentine E.
Published: July 2014

Determining the accurate amount of natural gas produced, consumed and distributed poses a significant challenge in the oil and gas industry. Thus, arise the need for proper confirmatory analysis of the produced gas volumes against the utilized volumes.

Operating companies often desire that the amount of gas produced (measured and recorded) to be properly utilized for accountability and economic reasons. The primary essence of accurate gas measurements is to ensure that accurate gas production reports are submitted to the government and to confirm that accurate gas volumes are handled by the production facilities. However, in some cases, optimum accuracy is never attained thereby generating erroneous gas measurements and also hampering right economic decisions.

This paper tends to address some of the impediments to accurate gas measurements and possible solutions of these problems. It also elaborates on the effects of various flow meters (i.e. orifice meters, ultrasonic meters) on the gas measurement readings and provides the frequency for proving and calibration of meter types and its corresponding effects on gas measurements. An onshore field (F3Y-field) was used as case study and was instrumental to providing a new procedure for computing the reported flare volume with greater accuracy with the help of gas balance equations.
Effect of Viscosity of Heavy Oil Class-A on Oil Recovery in SP Flooding Using Lauryl Sulphate and Gum Arabic
Authors: Atsenuwa Julie , Taiwo Oluwaseun , Dala Joshua , Mohammed Ismail , Olafuyi Olalekan
Published: July 2014

Chemical flooding methods are used to recover residual oil left after water flooding. Several chemical flooding processes have been used to improve recovery. Alkaline-free surfactant polymer combination flooding (SP flooding) can avoid side-effects encountered in alkali-surfactant-polymer (ASP flooding) combination flooding. As part of the ongoing research on the use of Gum Arabic as a polymer in chemical flooding in Nigeria, this paper investigates the effect of heavy oil viscosity on oil recovery during SP flooding.

Improved oil recovery through SP flooding was studied by conducting linear displacement experiments using engineering grade class IV glass beads. The glass beads were treated to be strongly water wet. The viscosity of oil samples used for the different experiments ranged from 3 to 140 cp. Lauryl Sulphate and Gum Arabic were used as the surfactant and polymer respectively.

Result shows that oil recovery by water flooding ranges from 15% – 25% and for SP 15% – 35% keeping the polymer concentration constant. Thus, increasing oil recovery can be achieved as the viscosities of oil increases. The result from this study will help develop effective methods for implementing SP flooding using Gum Arabic that is vastly available in Nigeria in heavy oil fields. It will give the oil industry a new option for improving oil recovery from heavy oil reservoirs.

SP flooding will be handy to improve oil recoveries from many marginal oil fields in Nigeria or those that face shut-down due to uneconomic operating cost, but still contain significant amount of oil.
Application of Seismic Inversion in the Identification of Common Hydrocarbon Fluid Contacts between Reservoirs
Authors: Jegede Temitope , Engel Stephan , Austin Anaevune , Mbah Reggy
Published: July 2014

Field X is located around the south-western part of Port-Harcourt and was discovered in 1965, but came on-stream in 1974. Six wells have been drilled in the field with two existing strings. There are two wells closed in, two wells abandoned and two wells suspended. There were no well repair or completion activities done on the field. There is a 10Mbpd capacity flow-station with a 4" export tie-in into the bulk line system.

The field is a 4-way dip closure consisting of two culminations separated by a saddle. Both structures are highly faulted E-W elongate anticlines and are bounded to the north by a boundary fault and open to the South. Wells 1 & 2 has produced while wells 3 and 5 were abandoned and wells 4 and 6 were suspended. Hydrocarbons were discovered between 7300 and 10000 feet in the C, D and E sands. 17 reservoirs have been identified and oil production has occurred from D5.0W in wells-1 and 2, but there has been no production from the Eastern Block.
Advancement in Material Balance Analysis
Authors: Kanu Austin Ukwu , Obi Onyekonwu Mike
Published: July 2014

The foremost objective of producing reservoir material balance analysis is to determine STOIIP and aquifer properties which ensure that the aquifer influx into the reservoir reliably offsets production. But the different views canvassed on this analysis are hampered by the limitation that the material balance equation is an ill-posed pressure-implicit depletion function. So, this program has adopted a robust and self-adaptive nonlinear regression to advance material balance analysis. The program validated two examples and pointed out the shortcomings of the authors solutions.
Efficient Drilling Time Optimization With Differential Evolution
Authors: Awotunde Abeeb A. , Mutasiem Mohammed A.
Published: July 2014

The drilling of an oil well is a very expensive operation. Consequently, asset teams often seek to minimize drilling costs by optimizing the drilling process. The most important factor in cost consideration is the length of time during which a drilling rig is hired. The fact that the rigs are often hired on a day rate means that the longer the drilling time, the higher the drilling cost. Thus drillers often seek to minimize the total time required to drill a well in order to minimize the drilling cost. However, the drilling time is often made of many components, some controllable and others uncontrollable. While the most common factor drillers seek to minimize is the time spent on the actual mechanical drilling of the well, this is not necessarily the most time consuming part of the drilling operations. Minimizing the time spent on the actual drilling is done by seeking optimum parameters that increase the rate of penetration of the bit. Another factor that may help reduce the total rig time is reducing the frequency at which the bottomhole assembly (BHA) is pulled out of hole to change worn out bits. Thus, it is important to optimize the drilling process to yield the lowest overall drilling time.

In this study, we proposed an optimization scheme that optimizes drilling operations by maximizing the drilling rate (ROP) and the bit life. The scheme optimizes drilling operations by finding the optimum values of drilling parameters that reduce the overall drilling time of any particular section of the formation. The drilling parameters we considered are RPM, WOB and mud flow rate. We used differential evolution as an optimizer to obtain the optimum ROP and optimum bit life that yield the lowest drilling time. We set upper and lower bounds for each of the operational parameters and tested the method on different sections.

Two cases are considered. The first maximizes the drilling rate (ROP) while the second minimizes the total time (i.e. mechanical drilling time and trip time and bit change time at the surface). Findings show that optimizing the ROP yields the lowest time at shallow depths. However, at deeper depths, optimizing the total time yields better the lowest overall time.

Significantly, the approach helps to identify the optimal values of drilling parameters at different hole sections needed to achieve the lowest overall drilling time. Hence, the method can save money that would otherwise have been used to hire the drilling rig for an extended period of time.
Application of Artificial Neural Network Control Model for Predicting the Pressure Distribution in a Complex Commingled Well
Authors: Ikezue E. N. , Onukwuli O. D.
Published: July 2014

Artificial neural network are closely modeled on biological processes for data processing, specifically the nervous system and its basic unit the neuron. The neuron receives multiple signals from other neuron through its dendrites each signal multiplied by a weighting function (Coefficient). These signals are added in the cell body or soma and when each component signal reaches a threshold value, a signal known as action potential is sent out through the axon which is the neurons output channel. Data obtained from a case study well were modeled and analyzed for predicting the pressure profile. The result showed that the pressure profile increased from 0.00 psia/cp and had an asymptotic limit at 220000 psia/cp at 400 psia-pressure and for temperature 100°F respectively. Then it increased from 0.01 psia/cp to 0.18 psia/cp (specific gravity 1.2) at a temperature of 100°F, the result was compared with those of Earlougher [3] and found to be valid for (1) radial flow (2) isotropic and homogeneous medium (3) general gas law applies. The case study well-opukusi 8 (escravos swamp field) south east Nigeria was monitored for 36 days period when it was shut-in for the pressure to build up and attain steady state to enable the prediction of productivity index which has the value of 0.60 which is indicative of a declining productivity.
Effect of Uncertainty in PVT Properties on CO2 EOR
Authors: Stanley Buduka
Published: July 2014

The aim of this study is to determine the impact of uncertainty in PVT properties on enhance oil recovery using CO2 Injection. A homogeneous 3D model using Eclipse 300 a compositional simulator was constructed with eleven components of hydrocarbon constituents present. The Peng –Robinson Equation of state (EOS) was used to characterize the fluids and the sensitivity study. The sensitivities were performed on the Binary interaction Coefficient, Fluid composition, miscibility, Temperature and Pressure of the reservoir system.

The studies show that Fluid composition has a significant impact on the reservoir recovery factor .The miscibility effect sensitivity also shows that the recovery improves as the process becomes more miscible, while the sensitivity on the Binary interaction coefficient has no effect on the recovery factor of the reservoir ,also reservoir fluid composition with heavier hydrocarbons is unsuitable for CO2 enhanced oil recovery due to low API gravity.

A 2D model sensitivity carried out on the temperature and pressure show that an increase in temperature gives an increase in the recovery based on the model, while a decrease in the reservoir pressure also has a significant increase in the reservoir recovery. The model result was linked to an economic model to determine the impact of uncertainty in PVT properties on the CO2 EOR to take economic decision based on economic indices such as NPV and IRR.
Guidelines for Uncertainty Assessment using Reservoir Simulation Models for Green- and Brown-field Situations
Authors: Ambastha Anil K.
Published: July 2014

Uncertainty assessment using reservoir simulation models for green- and brown-field situations has become a common practice. While capturing uncertainties in forecasts is required in all situations, developing multiple history-matched models is also an important goal for brownfield situations. Objective of this study is to provide systematic and practical guidelines for uncertainty assessment work using reservoir simulation models.

This paper discusses steps involved in any uncertainty assessment including selection of uncertain parameters and their ranges, practical experimental design methods, appropriate response or tracking functions (or variables), and data analysis techniques. Roles of lessons learnt from a base-case history-match exercise for a brownfield situation as well as earth modeling/petroleum engineering knowledge in setting up appropriate parameters and ranges are emphasized. Guidelines are provided to judge "quality of history match" based on prudent interpretation of response or tracking functions/variables. A Monte Carlo simulation-based methodology to develop multiple history-matched models for brownfield situations is presented in detail including practical tips on problem setup and analysis of results. Unique nature of uncertainties related to forecasting situations is discussed with an emphasis on a need to engage all operational and facilities personnel to develop adequate forecast problem description and economic success metrics. Guidelines presented in this paper are illustrated using a case study example. Practical tips presented in this paper would be of use to all reservoir simulation engineers carrying out uncertainty assessments.
Comparative Analysis of Permanent Downhole Gauges and their Applications
Authors: Enyekwe A. E. , Ajienka J. A.
Published: July 2014

Permanent Downhole Gauges (PDGs) are important accessories to run in with the completions of a well and are particularly crucial in offshore locations and deviated wells where intervention is uneconomical and risky. This paper performs a comparative analysis of the different technologies used in the design of PDGs. It outlines specific use and advantages of each of the sensor types used in PDGs. From the comparative analysis, optical sensors are the most versatile in terms of ability to measure a broad range of parameters and can survive harsh conditions of pressure and temperature. They are relatively expensive. Piezoelectric sensors such as Quartz or Sapphire crystals are also very robust but are limited to a range of temperatures and pressures. Silicon-on-insulator sensors are most useful in wells with artificial lift systems (ESP or Gas lift) as they can determine the efficiency of the artificial lift system. They are also limited by operational temperatures and pressures. Capillary tube pressure gauges are rugged and well suited for extreme conditions of temperature and pressure but cannot measure a wide range of parameters. Two quick-look flowcharts for selection of PDGs were developed and presented in this work as helpful output. One is based on well properties while the other is based on field properties. Economic implications are considered in both. A quick cross-reference of the two flowcharts can help investors in their selection of a PDG.
Practical Application of Multi Rate Deconvolution
Authors: Obeahon P. P. , Sedgwick A. , Okereke O.
Published: July 2014

Deconvolution is not a new interpretation method or a replacement of conventional methods in the analysis of well test data. It is rather a process that is used to convert variable rate pressure data into constant rate pressure data thereby providing more pressure data for the determination of an interpretation model. The usage of this robust method is not widespread among Reservoir Engineers resulting into missed opportunities or benefits in its application.

To stimulate more widespread usage, this paper presents the results of three case studies demonstrating how deconvolution can aid in reservoir characterization. The success of applying this technique depends a lot on the quality of the test data and on the deconvolution algorithm applied. This was applied to reservoirs with single well.

The first case study involves a retrograde gas condensate reservoir Z100 in the Niger Delta, Here deconvolution was used to predict initial reservoir pressure (Pi) from Multi rate test (MRT) data and validate boundary response obtained from single pressure build up (PBU) analysis. The second case study involves a wet gas reservoir Z200 in the same field as the Z100. Prior to drilling, it was estimated from analogue data that the proposed well would recover 154Bscf. Following completion of the well an MRT was conducted. Numerically matching the deconvolved response of all available flow periods showed that the well will drain 148Bscf. This shows an acceptable 0.4% deviation. The third case study involves an oil field N100 in the North Sea. Here, deconvolving 8 years of production showed that connected Stock Tank Oil Initially-In Place (STOIIP) had increased due to dynamic fault seal failure. The origin of the fault seal failure as well as Pi was estimated. The result is consistent with the 2005 4D seismic interpretation acquired in this field.

These three case studies demonstrate that deconvolution can aid in Pi estimation, better estimation reserve evaluation, dynamic fault seal analysis, and potentially reduce the level of uncertainty and non-uniqueness of PTA. A procedure on how to use deconvolution in reserve estimation is also presented. It is hoped that this paper having highlighted the merits of deconvolution will encourage reservoir engineers to use this technique more confidently.
Managing Waterflood in Deepwater Soft Rock: The Bonga Experience to Date
Authors: Olatunbosun Olugbenga
Published: July 2014

The Bonga field came on stream in November 2005 with 16 predrilled wells (9 producers and 7 water injectors). The field is characterised by unconsolidated rock but with permeabilities in the multi darcy range. The reservoirs are undersaturated and contain light crudes in the 28-35 deg API range. The field contains STOIIP of over 4 billion barrels across 6 reservoirs and it is developed by waterflood. The reservoir characteristics have culminated in high injection and production rates per well with injection rates above 60 kbpd and production rates above 50 kbpd achieved for some wells.

Plateau field production and injection was achieved soon after start up with production and injection at or near nameplate capacities of 225 kbopd and 300kbwpd respectively. This continued until H1 2008 when injectivity decline set in. As water breakthrough had already occurred, the reduced deliverability of the water injectors further compromised the voidage replacement capacity of the system. Net result was that the field fell off plateau but production was soon restored to near plateau level. Since then, production has been off plateau intermittently with the integrated team taking action to ameliorate the situation and to bring the field back to near plateau level of some 200 kbopd. The key issues/challenges that have resulted in production decline include: injector impairment, inadequate topsides injection capacity, injection well failures, baffles mitigating injector-producer connectivity, producer impairment, ScSSV failures, injector longevity, injection water quality, produced water handling, premature water breakthrough.

Cross discipline corrective and innovative measures have been taken to address the above challenges and maximise value from this field. The measures cut across subsurface, wells, topsides, subsea and production operations disciplines and include: Backflush/refrac, acid stimulation, increased injection capacity, improved injection water quality, fracture mode injection only, drilling of horizontal wells as preferred option for injectors, breaking down of connectivity baffles by sustained high rate water injection etc. This paper captures the key learnings from the Bonga experience and the corrective measures applied. The field overview and performance history of the field are illustrated in figs 1&2.
Synthesis and Applications of Nanomaterials in Enhanced Oil Recovery
Authors: Odedele Engr T.
Published: July 2014

Given the large amount of by-passed oil and gas and low oil recovery factors in many reservoirs coupled with global energy demand projected to rise as high as almost 60%in the next 30 years particularly in Africa, it is quite evident that convectional petroleum engineering techniques are not adequate and efficient for reservoir characterization and production optimization. This challenging trend may be met only by revolutionary breakthroughs in energy science and technology. The industry thus requires stunning discoveries in underlying core science and engineering which can only be accomplished through integration and global approach. Breakthroughs in nanotechnology open up the possibility of enhancing and optimizing oil and gas production beyond the current available technology by introducing innovative concepts that are more efficient and environmentally friendly. The term “nanotechnology” covers processes associated with the creation and utilization of structures in the 1.0 nanometer (nm) to 100 nm range. Nanofabrication involves engineering at the atomic length scale. It no doubt, offers substantial economic and societal benefits than any technology and holds the promise of both incremental improvements of existing products and the potential for revolutionary changes that could transform entire industries. Nanotechnology is characterized to be a multidisciplinary field, making it inherently innovative and more precise than other technologies. In this paper, the greatest potential for innovative solutions in enhanced oil recovery (particularly water flooding) through the investigation and synthesis of water-based nano-particle will be discussed.
Integrated Multidisciplinary Pore Pressure Prediction Leads to Accurate Casing Design: A Case Study
Authors: Effiowan Akiba Eyo , Umahi Otuka , Richard Ebisike , Tunde Alabi , Lamens Jo , Oyibo Alphonsus
Published: July 2014

The well design of LT- 4 and LT- 5 wells in the Niger delta is evidence that application of current 3-D seismic technology, accurate modelling and RFT data with inclusion of offset well information lead to improved pore pressure and fracture gradient predictions.

The LT field had no cores, no PVT samples, nor production history. Seismic modelling by geologists and geophysicists observed a pressure trend above hydrostatic from 10, 600ftTVDSS which corresponds to the 17.4MFS. Pressure data (RFT) from offset wells and other drilling performance data (FIT, mud weight, kick pressure) from wells drilled in the wider area were used to constrain the pressure prediction. Two distinct pressure ramps were observed from the plot, coinciding with the base of the 17.4MFS and 19.4MFS respectively (fig. 2.1) which illustrates the geological control on overpressures. The kill mud weight data indicated from offset wells in which kicks occurred provided information on overpressures in the 8 ½” hole sections. The pore pressure evaluation over pressures in the deepest zones would not have been predicted based only on either the other pressure data (RFT) available or on the seismic velocity data.

Sensitivity analysis of the pore pressure prediction with inclusion of the well kick data for the well planning and design provided a more robust basis for design resulting in selection of an appropriate intermediate casing weight and grade.

This paper presents a case study of the LT- 4 and LT-5 wells showing how an effective casing design which depends on an accurate pore pressure prediction can be achieved through integration of seismic calibration and offset well information.
A Robust Way of Managing Water and Gas Encroachment Modeling Issues in a Matured Reservoir with Dip Complexity
Authors: Suleiman Ahmed , Peter Joseph
Published: July 2014

Robust re-development and management of brown field depends on having an integrated reservoir model that can reliably replicate performance history, and predict future performance in form of acceptable and consistent production forecasts that can be validated with other methods. This often involves integration of all geosciences and petroleum engineering data in a relatively fine simulation model which, although captures the heterogeneities in the reservoir to some more detailed level, usually takes up so much CPU space and long model's runtime. Typically, a shorter runtime can be achieved by building a coarser static model, and/or upscaling finer static model that will lead to the loss of some of the reservoir's pecularities. Such coarser models are normally impacted by many shortcomings, most important of which is numerical dispersion that result in spurious gas cusping or water encroachment/coning issues. These problems are more critical in reservoirs with high dipping structure or in model with some random skewed or dipping cells. This paper demonstrates a robust methodology of managing these issues of long run time and not compromising on quality of result.

This case study was on a 67 ft oil-rim reservoir (20km × 8km) with huge overlying gas cap and long production history in the Niger Delta. The wells in this reservoir are characterized by some water coning and gas cusping problems.

In order to achieve shorter models runtimes while still preserving key reservoir details, a relatively coarse static model was constructed based on consistent geological concepts incorporating all relevant geosciences and Petroleum Engineering data. Preliminary attempts made towards using the coarse model to achieve acceptable history match failed, largely due to numerical dispersion issues arising from high dipping model cells around areas with slight increase in structural dip. The model was subsequently updated by "refinement" of the high dipping cells at the free water level interface only. The updated model, whilst still fast, achieved acceptable history match within the defined uncertainty envelop, which could only have been achieved by a very fine model that will take order of magnitude time to run.

Based on the model derived using this approach, more than 12 hours of model runtime was saved, the existing well behaviours were better replicated and few new drilling opportunities were identified. The use of this robust approach results in a better understanding of the subsurface and delivers new opportunities which will ultimately enable more optimal (faster decision making) management/development of the field.
Development of a Self Configuring Mesh Network Architecture for Digital Oilfield Implementation
Authors: Idachaba Francis Enejo
Published: July 2014

The Mesh network architecture provides a robust architecture for ad-hoc wireless communication networks utilizing low power transceiver for short hop links. The key advantages of this architecture include the ability of the network to configure itself and setup a transmission path between the different nodes. The requirement for all the nodes in the mesh network to be ON makes it unattractive for digital oilfield (DOF) implementations in both onshore and offshore Oil and Gas production installations due to the drain on the power supply. The self-configuring mesh network topology proposed in this work extends the coverage of the wireless sensor networks deployed in DOF implementations by maximizing the advantages of the mesh network and the power saving configurations of the star topology currently used in DOF implementations. It utilizes a set of algorithms which enables the Remote Terminal Units (RTU) to go into sleep mode without impacting on the real-time communication advantage of the mesh network. These algorithms enable the system to setup neighborhood cells comprising of RTUs within its coverage and identify multiple transmission paths in the event of a failure of the main link. This architecture allows more RTUs to communicate with the gateway using short hops thereby increasing data reliability. The short transmit distance extends the battery life and maximizes the gateway license as more RTUs can be linked to access the same gateway. The synchronization algorithm also enables longer battery life for the RTUs by ensuring that the RTUs operate in the sleep mode. The topology will increase the data reliability and reduce both the OPEX and CAPEX required for setting up the communication links in DOF implementations in both onshore and offshore installations.
Industry-Academia Collaborations. The Shell Sabbatical Model
Authors: Idachaba Francis Enejo
Published: July 2014

The quality of graduates produced by any institution is assessed by the ability of those graduates to add value to the business of their employers. Research has shown that the factors with the greatest impact on the quality of the graduates include the quality of the curriculum, the delivery method, the quality of the lecturers and the motivation of the students. The shell sabbatical model takes University lecturers with relevant proposals and integrates them into the company for a period of One year giving them the opportunity of participating fully in the company operations. This provides them with an opportunity to learn the culture of the industry and understand the skill requirement of the industry while contributing to the company business. It also provides these lecturers with an insight into the needs of the industry thus shaping their research directions. This model impacts on the quality of the lecturer, the curriculum and the teaching method by providing the lecturer with access to the latest technology in the industry, enabling the lecturer to identify relevant modifications that should be made to the curriculum of his courses and changing his teaching methods as he is now able to teach with practical examples and real life illustrations and scenarios. This also results in an increased motivation as they are taught with real life scenarios and examples. This paper reviews the Shell sabbatical model and presents some results on its impact on the University lecturer, the industry, the student and the Nigerian educational system.
Modelling a Complex Niger Delta Reservoir for Secondary Recovery: The Use of Assisted History Matching for Improved Uncertainty Management
Authors: Mijinyawa A.
Published: July 2014

The model maturation method proposed by Joosten et al (Joosten et al, 2011) was applied to a large, complex and mature Niger Delta reservoir system aimed at obtaining a range of acceptable history-matches as basis for evaluating the feasibility of water injection. The method involved forcing gridblock level changes in reservoir properties to obtain model matches for observed field performance. These changes were then used as feedback to improve/update the geo-thinking (understanding of the subsurface).

Of the various model maturation components/types in use, a combination of Experimental Design (ED) with the Adjoint methods of assisted history matching was employed. The first stage involved the assessment of the initial uncertainty space using ED techniques. This resulted in the identification of the most significant uncertainty parameters with respect to key history-match criteria and led to a reduction in the size of the uncertainty parameter space. This reduced (more manageable) space formed the input into the Adjoint process which essentially involved the (automated) identification of the location and extent of changes in gridblock permeability required to improve the model response vis-à-vis production performance.

Despite previous examples of the successful application of this approach to integrated reservoir modelling (Joosten et al, 2011), results in this case showed that it was not entirely possible to fully account for all the forced permeability changes from both a subsurface and surface perspective. A number of reasons were identified for this outcome. Chief amongst these is the lack of a full understanding of the dynamic behaviour of the (complex) faulting in the field. In the end, a compromise position was adopted where the extent and location of changes in gridblock permeability was restricted based on observed well log information. This position was adjudged to still give acceptable history-match results that could reasonably be used to underpin the water flood project.
Structural Modelling of a Mature Field in The Niger Delta Basin: The Benefits of Integrating Production Data for Uncertainty Management
Authors: Adenaiye Olaniyi , Jude-Ofia Ifeyinwa , Adekoya Oluwaseyi , Kirchner Andreas , Nwonodi Chike , Campero Manuel , Anosike Ebere
Published: July 2014

This paper highlights the importance and benefits of integrating both static and dynamic data, in defining the range of structural uncertainties in a mature field in the Niger Delta Basin. Appropriate management of static and dynamic subsurface uncertainties enhances the prediction of the subsurface and improves the quality of key development decisions. Typically, structural uncertainty ranges are mostly associated with seismic and geologic data (e.g., seismic loop pick, fault positioning/geometry and velocity model for time-to-depth conversion etc.), while dynamic data (e.g., production data) are rarely considered.

To model the mature ‘A-sands’ in Craig field, a subsurface uncertainty matrix was generated consisting of all identified uncertainties as well as their ranges. Low, base and high case structural and static models were built in Petrel for the ‘A-sands’ and then transferred to a dynamic simulator for history matching and to assess impact of these uncertainties on ultimate recovery. Experimental Design (ED) technique was used during dynamic modelling to integrate all the uncertainty parameters with the aim of selecting the best history-match realizations that will be used for forecasting.

Initial results obtained from ED indicated acceptable history matches for the base case model, while the quality of matches for low and high case models were poor / unacceptable, suggesting a need to review the uncertainty ranges. This was further supported by a narrow range of recoveries obtained from DCA (decline curve analyses) for the producing conduits in the reservoirs. Also considering the maturity of the field (over 70 wells drilled, with Np over 30% of the oil in-place), it was pertinent to revisit the ranges

Based on these informations, the uncertainty ranges were reviewed, with focus on those that have the largest impact on history match results. This paper focuses on the review carried out on the structural uncertainty - which has the largest impact on history match results - leading to smaller ranges of structural uncertainties. The reduced depth uncertainty values resulted in static models and volumetric estimates that supported historic production data for the reservoirs, producing much improved history matches.
Use of Centrifuge to Determine Connate Water and Capillary Pressure from Unconsolidated Cores
Authors: Ubani Ebenezer Chikwendu , Oriji Boniface Aleruchi
Published: July 2014

The centrifuge has been found to be a useful tool for determining, capillary pressure and connote water saturation from unconsolidated cores. The method has also demonstrated the virtue of simplicity, reproducibility, speed and good correlation with other methods. Hence, this study is in response to the need of providing practical experimental evidence to justify the use of this method in preference to other methods (Porous plate and Mercury injection Methods). The samples for this study are cores taken from different fields located onshore and offshore of the Niger Delta. Their porosity ranges from 17-35% and permeability from 100-3500 md. These unconsolidated and friable sandstones cores are susceptible to deformation grain re-arrangement and grain losses, while vuggy cores are susceptible to surface drainage. The severity of these occurrences were minimized by drilling the samples with liquid nitrogen, mounting the samples with tin sleeve and protecting both ends with a pairs of screens of 100 and 135 U.s mesh size. The capillary pressure and corresponding saturation data obtained from the experiment are displayed in the tables. Also capillary pressure curves were obtained to show the relationship between the capillary pressure and saturation for each of the sample tested. From the capillary pressure curves, the end point saturation of the primary drainage process of the sample show low irreducible water saturation (Swi) and high permeability. The centrifuge method is however limited because numerical differentiation and integration of functions defined by the measured data are needed; and the assumption of 100% wetting - phase saturation (i.e. Pc = 0) at the sample bottom may not be valid beyond a certain rotational speed. The measured data may need interpolation to avoid oscillation in the Solution. This interpolation however only represents "Smoothing" of the experimental curve which is always done for experimental data. Application of the centrifuge procedure to unconsolidated sand stones provide results, which are in good agreement with those obtained from other techniques.
Experimental Determination of Relative Permeability from Unconsolidated Core Samples of The Niger Delta
Authors: Ubani C. E , Ikiensikimama S. S , Onyekonwu M. O
Published: July 2014

A procedure have been developed and tested for measurement and evaluation of water-oil relative permeability characteristics from unconsolidated core samples; in an unsteady state displacement experiment. In this work a simple core flooding experiment was designed, with emphases on the rate of injection, critical velocity, brine-rock compatibility, pressure response of the core sample and net over burden. This procedure proposed here besides being fast and cheap, presents the advantages of permitting the displacement to be conducted at pre-determined rates more typical to that of the reservoirs.

This research work is in response to: (1) the need of practical experimental evidence to justify the use of unsteady state method in preference to other methods. (2) The need to obtain relative permeability data from unconsolidated formation of the Niger Delta, which could be used to correlate other un-cored formation in the region.

The samples for this analysis were taken from seven (7) different locations representing the depositional belt of Niger Delta. Their porosity and permeability ranges from 18-34% and 100-20,000md respectively. These unconsolidated and friable sand stones are susceptible to deformations, grain re-arrangement, grain losses and surface drainage. The severity of these occurrences were minimized by drilling the plugs with liquid nitrogen, mounting the plugs with tin sleeve and protecting both ends of the plugs with a pair of screen of 100 and 135 us mesh size.

Also, it was possible to avoid potential problem of EOR'S such as fines mobilization, precipitation, scaling, clay swelling and compatibility of other chemical flooding agents.

This method involves performing low rate displacement of brine with oil and oil with brine and measurement of liquid permeability at irreducible – water and residual – oil end point saturation.

Except for the added provision of stopping, restarting and reversing the flood after end point have been reached, the pressure drop across the core is measured externally, between the inlet and out let of the system.

The measurement and analytical interpretation of the experimental variable, using a combination of the modified Darcy equation and our developed semi-empirical model make for quick calculation of relative permeability from the unconsolidated core samples.
Remote Pipeline Pressure Monitoring Using Low Power Wireless Transmission
Authors: Idachaba Francis Enejo , Okuns Godwin , Wokoma Esther
Published: July 2014

Manual data acquisition of pressure readings in order to build a static pipeline hydraulic profile for a pipeline network, increases the security exposure of personnel, logistics cost with the attendant delay in determining and reporting pipeline pressure used in Hydrocarbon accounting, making it prone to errors, inaccurate and unrepresentative of the actual situations on the network. This paper presents results of a wireless pipeline real time (RT) pressure monitoring system using low power wireless transmitters installed at selected pressure points on the pipeline networks located in remote areas of SPDC operations. The system utilizes secure wireless transmission and special encryption systems designed to protect the data transmission from interference and degradation. The system achieved a data transmission over a 10km range from a pipeline pressure point to the gateway, with a battery life of over 6 months. Longer battery life durations can be achieved by the deployment of exception based reporting. The system provides a means of monitoring the pipeline pressure and thus enables the development of a dynamic pipeline pressure profile for the monitored pipelines. The data from the system can also be used with special algorithms to monitor the pipeline for leaks. The system versatility has also been tested as means of collating vital well data to a data concentrator enroute an enterprise intranet
Fracture Gradient Estimation in the Niger Delta – A Practical and Statistical Approach
Authors: Reginald-Ugwuadu Onyinye G , Alabi Tunde I , Eze Joy O , Ebisike Richard C
Published: July 2014

The safety of lives, assets and environment continue to remain the key challenges facing the oil and gas industry in its drilling and completions operations. One important factor in ensuring that wells are drilled and completed to desired depth is the formation strength or pressure containment of the shoe after a cement job to help ensure zonal isolation around the casing shoe as well as pressure containment at the shoe while drilling the next hole section.

The knowledge of formation strength estimate is essential to enhance proper planning of these wells and drilling to desired total depth, and forestalls, or at the least minimises the likelihood of not drilling to optimum depth or incomplete evaluation of the prospect.

Additionally, other key well construction aspects such as determining optimum mud weight required for borehole stability especially in deviated wells; optimum casing setting depth selection where the pore pressure profile below the shoe is known are highly dependent on accurate knowledge of the formation strength estimate.

Historically, there have been several methods to predict fracture gradient, most and/or a combination of the methods have been adopted by many operating companies. Several operating companies have drilled so many wells in certain fields such that formation integrity test data (Leak-Off test and Limit tests) exist for the several formations that have been traversed by these wells. The industry has great reliance on the use of offset correlating wells data in well planning and designs.

In this study, several Leak-Off (LOT) test data from different wells across fields in the Niger Delta were used to determine a correlation between increase in formation strength and depth. A practical statistical method is used to derive equations for fracture gradient estimation in Onshore and Swamp Niger Delta using existing wells leak off test database. Limited data for the shallow offshore were also used to derive an equation which has proven to work. These set of equations can be used to estimate fracture gradient expected in the formations across these and nearby fields. The formation leak-off gradient has been assumed to be an approximate representation of the formation strength or formation breakdown gradient. Since the latter is always greater, the use of the former for well design purposes provides an additional factor of safety.
Optimizing Sand Control Design Using Sand Screen Retention Testing
Authors: Agunloye Ehimhen , Utunedi Erome
Published: July 2014

Sand retention tests have been widely accepted as one of the methods of sizing screens for Stand Alone Screens (SAS) in open hole completions. The results of such tests are, however, highly dependent on the experimental conditions and prone to artefacts; small and apparently innocuous changes to the test conditions can cause wide variations in results1. Furthermore it may require several tests performed with different screen and test sands to adequately select the appropriate screen size that would prevent plugging and sand production. When done correctly sand retention tests have proven to be an optimum method for SAS sizing.

Several mathematical models have also been developed for screen sizing using series of laboratory data but the applicability of these models to other reservoirs, different from the test reservoir, is questionable.

This paper discusses screen selection for a highly non-uniform unconsolidated reservoir in a field in the Gulf of Guinea based on sand screen retention test using screen sizes pre-selected on Coberly's criterion. Coberly's criterion is extensively used in the industry for screen only design. It is however still subject to debate most especially with respect to sand control failure due to plugged screens, or catastrophic failures due to screen erosion.

The optimization work goes further to compare the results of the screen retention test in the laboratory against published numerical models, by applying these models to the field in question. From the results, a detailed experimental workflow for sand control design and screen selection for unconsolidated reservoirs has been developed for the Region; this also includes the sand screen retention testing applicability and requirements for a successful design.