bluuebunny/crossref_metadata_2025 huggingface dataset:
Pre-and Post Stimulation Diagnostics using Spectral Noise Logging. Case Study.
Authors: Volkov M. , Ellis R. , Khabibullin M , Uralsky S.
Published: October 2018

Tight or damaged reservoir sections often require stimulation to adequately perform. These sections can be identified as the well is drilled using LWD measurements and after drilling using open-hole wireline tools (RFTs, borehole imaging, and petrophysical logs). After the completion is run it is often impossible to make these measurements again, meaning that when sections are stimulated the only way to gauge stimulation effectivity is by measuring the change in flow rate within the completion, e.g. through a frac port. The physical reservoir response is not realized. Spectral Noise Logging can be used before and after each stage of a stimulation job to evaluate this response.

SNL distinguishes between matrix and fracture contribution (G. Galli, 2015) to flow allowing assessment of both hydraulic fracturing stimulation and acidizing. Acquiring behind pipe flow profile before the first stimulation stage will provide the baseline. SNL reservoir flow profile can be compared to open-hole logs (e.g. borehole imaging) and used to calibrate them with flow activity as the reference e.g. fractures identified from a formation imager can be seen and categorized as flowing or not flowing (Arthur Aslanyan, 2015). Logging SNL after the first stage of stimulation reveals how the reservoir responds, e.g. improved or new flow through existing fractures (comparing with borehole images), the appearance of new active fractures or change in matrix flow activity. If different stimulation strategies are implemented in the same well or reservoir, SNL can be used to assess and compare the effectiveness of each, resulting in the identification of an optimum stimulation technique.

How effective a stimulation job is largely dependant on the conformance of the completion of the job. If two zones have been targeted with some volume of a stimulation fluid, but a portion of this fluid leaks off to adjacent zones (e.g. through leaking packers) this will impact the degree to which the target zones react. Evaluating completion integrity is therefore crucial to understanding the effectiveness of a stimulation technique. Spectral Noise Logging is used to detect such leaks (Ihab Nabil Mohamed, 2012) making it integral to a wholistic approach in diagnosing stimulation effectivity. Furthermore, for many cases, well conditions render conventional PLT data useless (e.g. cross-flows dominate temperature profile, asphaltenes/solids affect spinner data) so noise data is the only measurement that can represent reservoir activity.

This paper will give such examples where SNL has been used to evaluate the effectiveness of stimulation jobs.
Future Implications of Global Renewable and Unconventional Energy Development on Nigerian Petroleum Sector
Authors: Onyije Israel Jackson , Nwaozuzu Chijioke , Iledare Omowumi
Published: October 2018

One of the most critical advances in the energy sector of the 21st century is the surge in technological developments that made renewable and unconventional (shale oil, shale gas) economically viable energy sources. These developments, in addition to environmental concerns and the quest for sustainable development precipitated a flux in global energy demand and supply dynamics, with huge implications on energy (petroleum) prices. Nigeria is one of the major petroleum exporting countries, whose economy depends almost exclusively on oil (accounting for nearly 90% of total foreign trade, and 80% of foreign exchange revenue), even though the sector contributes less than 20% to national gross domestic product. Presently, the nation is struggling to gain a quantum leap from the current economic recession orchestrated in part, by the slump in global oil price since mid-2014. This negative impact on the economy signal potentials of more severe consequences in the future, especially as major oil consuming economies are realigning their energy policies in favor of low carbon economy. Providentially, it is important to assess the dynamism in the global energy landscape, with a view to furnishing Nigeria's economic and policy makers with information adequate for situating the country on the right pedestal so as to remain relevant both regionally and globally. This is the object of the present study. We use available global statistics (from IEA, US EIA, OPEC and NNPC) and scenarios of energy supply & demand dynamics, to assess the implication for the Nigerian oil and gas sector, as well as the potential market opportunities available for the country. Our analysis showed Nigeria's oil and gas export may face stiff competition in the international oil market. The study recommended diversification of revenue sources; and also energy alliance opportunities, especially with high energy consuming economies like India.
Optimizing Water Injection Operational Parameters for Improved Oil Recovery
Authors: Aigbogun Justifed Feyi , Fusier Francis , Esene Cleverson Ebeagbor
Published: October 2018

The demand for energy has been on a steady rise and oil production from world reserves remains the major source of energy generation; therefore, primary recovery methods alone are insufficient to sustain economic oil production. By supplementing the natural energy of the reservoir through secondary recovery techniques, an incremental recovery factor ranging from 15% to 25% usually can be achieved. This makes water injection feasible and economically attractive as it would allow for increased production rates.

This paper is focused on the incremental recovery that can possibly be achieved by optimizing the operational parameters of water injection. A reservoir in the Niger Delta region of Nigeria, Reservoir OD-50 was used to illustrate this. Reservoir OD-50 has an estimated STOIIP of 267MMbbls and a recovery factor of 32%, and is planned to be developed alongside water injection for pressure maintenance and improved recovery. This work was done to determine the additional oil can be produced by optimizing the operational parameters affecting the efficiency of water injection.

Parameters such as injection rate, time of commencement of injection, contributing drain lengths, well types, bottom hole pressures and tubing head pressures were studied as sensitivities in this work and an optimized case with the most influential parameters on the recovery was obtained. The optimized case resulted in an additional oil recovery factor of 1% and from the economic analyses, the NPV was increased from $293.06M to $305.25M, the IRR from 27.1% to 27.4%, and the PI from 1.44 to 1.46.
Bubblepoint Pressure Mathematical Modelling for Nigeria Crude Oil
Authors: Adeeyo Yisa Ademola
Published: October 2018

Bubblepoint pressure is a fundamental factor in reservoir management and reservoir engineering calculations. Ideally, the lab measurements of reservoir fluid properties of samples collected from the bottom of the wellbore or from the surface are the primary sources of bubblepoint pressure. Such experimental data are, however, not always available because of one or more of such reasons as samples collected are not reliable or samples have not been taken because of cost saving. In this circumstance the notable among published empirical models are perused and used to predict bubblepoint pressure. These empirical models were developed by fitting equations for a certain range of PVT parameters using large sets of measurements of these parameters. Unfortunately, some of these correlations are incorrect, especially when used to predict bubblepoint pressure of crude from a different region and or different range of crude characteristics.

This study examined the available models using classic statistic criteria and developed a new bubblepoint pressure model.

I have used more than 2580 unpublished PVT data sets from different locations in Nigeria in developing the model. The model development workflow considered the impact of each independent variable on the bubblepoint pressure, pairwise plots to show evidence of nonlinearity, stepwise regression dimensionality reduction (backward selection method) and variance. Model parameter estimation was based on a search method from the optimization that minimized the norm of residual vector/error. The new model was subjected to standard statistical tests. These tests established logical validity as well as the statistical measures of the suitability of the model.

The results of the comparative study between existing correlations and new model show that the new model provides a more remarkable and reliable performance.
Performance Assessment of Nigeria E&P Operators Using Data Envelopment Analysis DEA
Authors: Idowu Joseph Adekunle , Iledare Omowunmi O. , Adeogun Oyebimpe , Echendu Joseph C.
Published: October 2018

The paper aims to; estimate relative technical efficiency (RTE) for each of the Nigeria 32 active Operators using vDEA model, rank the performance of the Operators considering output orientation, categorize each of the Operators into its respective return to scale (RTS) group using Non-Increasing Return to Scale model (NIRTSM) and suggest necessary policies that could improve the performance of the Operators.

The approach is based on variable return to scale assumption of DEA model framework (vDEA). Based on this, four variables were considered; two inputs, petroleum reserves in million BOE and Number of producing Wells and two outputs; total annual oil production in million BBLS, total annual gas production in million SCF. vDEA model assumes operational variability due to constraints such as: projects financing, competition, government policies, operational terrains, etc. A dual linear programming model (DLPM) is formulated and a Microsoft excel solver aided with a visual basic application (VBA) is used to generate RTE for each Operator simultaneously. RTS indexes are estimated using output oriented NIRTSM. The relationship between the two models' results is used to categorize each Operator into different production scale group.

The empirical results reveal a decreasing trend in the Operators' RTEs from 2010 to 2016. Twelve (12) of the Operators were operating on efficient production frontier within the period under investigation. Based on this, Operators were classified into three different production scale group. Eight (8 or 25%) were operating on decreasing return to scale (DRTS), Six (6 or 19%) on constant return to scale (CRTS) while the remaining Eighteen (18 or 56%) were on increasing return to scale (IRTS). Significantly, it is discovered that more than 80% of the JV Operators have been operating on DRTS.

Consequently, the paper provides information on RTEs of the 32 active upstream Operators in Nigeria considering more realistic assumptions as recommended, (Idowu and Iledare, 2018). Operators performance is ranked based on estimated RTE indexes as well as production maximization consideration. The paper proposes policies such as: splitting of JVs companies into two or more to minimize bureaucracies and facilitate new efficiency-oriented ideas, merging of companies under IRTS to enhance internal growth and embarking on aggressive reserves growth policy to increase the reserves base of the 6 Operators on CRTS.
Evaluating and Inhibiting Gum Formation Tendencies in Gas Condensates
Authors: Bamidele Taiwo , Onuigbo-Nweze Chy , Osuagwu Michael , Azubuike Achara , Joel Ogbonna , Onyewuchi Akaranta
Published: October 2018

A report is presented on the evaluation of gum formation tendencies of natural gas condensates from two gas fields in the Niger Delta region of Nigeria. Following reports that certain condensates from the region have high gum formation tendencies and thus their market prices devalued, a study was embarked upon to evaluate and inhibit the formation tendencies of these condensates, if any. The reports indicated that there was general consternation around high unwashed gum contents and this parameter was sometimes considered in conjunction with the washed gum contents when devaluing the condensates in question.

To investigate the suitability of current evaluation methods, a review of ASTM D381, the gum test method developed for gasoline and jet fuels which is now being applied to gas condensates, was carried out. Further tests such as fingerprinting, boiling ranges and asphaltene content were also carried out. To investigate the effectiveness of anti-oxidant injection in inhibiting gum formation, two products were selected and injected into a condensate sample at varying concentrations and the gum content of resulting mixture was tested using ASTM D381.

The results show that while ASTM D381 was developed for gasoline and jet fuels, its use for these products is not firmly established and thus, its extension to gas condensates is even more uncertain. This is because heavy hydrocarbon fractions which are not present in processed fuels are present in condensates. Thus, the typical values of unwashed gum content in refined liquids cannot be expected of condensates where they are bound to be significantly higher. For the samples under-investigation, confirmatory tests using boiling ranges as a complement to the n-heptane washing step of ASTM D381 supported the observation that >60% of the unwashed residue was not gum, but instead naturally-occurring heavy hydrocarbon fractions which would not normally evaporate under the test conditions of ASTM D381. Furthermore, the use of antioxidants at high concentrations showed a decrease in the washed gum content. However, the decrease was only achieved at very high concentrations.

Insights made from this study presents the industry with evidence that the existing method for evaluating gum content in only applicable to gas condensates as far as the washed gum content in concerned. Condensate quality concerns based on unwashed gum content are unfounded and thus, should not be considered by suppliers and buyers of condensates. Furthermore, it is recommended that the further work be carried out to develop and/or evaluate antioxidant chemistries that are cost-effective and can perform at lower concentrations.
Measurement of the Wax Appearance Temperature of a Gas Condensate Using High Pressure Microscopy Technique
Authors: Mmata Bella , Onyekonwu Mike
Published: October 2018

Wax precipitation and deposition is a major flow assurance problem usually encountered with waxy fluids. Often times, crude oil systems are subjected to flow assurance test while exempting gas systems. Studies have shown however, that gas condensates can also be waxy in nature. The major test used to assess the potential of a hydrocarbon system to cause wax associated problem is the wax appearance temperature (WAT). Experimentally measured WAT is required for the development and validation of wax thermodynamic models as well as the successful design and operation of a hydrocarbon production system. Well head sample collected onshore the Niger Delta region was used for this study. The sample was confirmed earlier to be a gas condensate with a dew point pressure of 4948 psia at reservoir temperature of 230.5°F through a constant composition expansion (CCE) test. The reservoir fluid particle (RFP) analyzer equipped with a high pressure microscope (HPM) was used to investigate the wax appearance temperature (WAT) of the gas condensate at well head pressure. Under a magnification of X5000, the phase change and wax precipitation of the gas condensate was observed at 84.2°F. This was also captured as real time photographs by the HPM and the photographs are presented in this work. In addition, pour point, wax content and API gravity measurements were carried out on the stock tank liquid obtained from a flash process. The outcome of this work stresses the need to carry out flow assurance studies on gas condensates to determine waxy tendency. This information will help to avoid or reduce the technical and economic concerns that are associated with production of waxy fluids.
Reservoir Management Best Practices and Lessons Learned from the Agbami Field
Authors: Jeboda Olatunji , Bodunrin Abiodun , Atuanya Chukwuma , Ogidi Emmanuel
Published: October 2018

The Agbami field is a Chevron operated deepwater asset located offshore Nigeria, approximately 70 miles off the coast of Nigeria and within about 4,800 feet of water depth. The field was discovered in 1998 and has been on production since July 2008. The field achieved peak production of 250 MBOPD in August 2009 and has produced over 770 MMBO as at year end 2017.

The field development plan approved at project sanction adopted a production strategy of mid-flank oil production with pressure support provided through peripheral water injection and crestal gas injection of the produced gas. The field development plan had a phased approach with three phases of development such that learnings are incorporated into the next development phase. The initial three phases of development are almost completed with 37 of the 38 planned wells drilled and supporting production while the next phase of development has recently been approved to drill more wells in two development phases.

The field has benefited from the phased development approach and the opportunity to use the rich sets of data acquired to improve performance for the next phase. The newly sanctioned project will also continue to leverage from lessons learned and best practices from previous phases which will be used to refine the development opportunities and improve the performance. The Agbami field is truly a world class asset with 40 existing wells and continues to produce at annual average rates exceeding 230 MBOPD.

This paper will highlight the performance of the Agbami field to date, discuss some challenges that have been encountered and share examples of reservoir management best practices such as real-time monitoring and optimization, formation pressure data analysis, 4D seismic acquisition and how the team has utilized these rich data set to optimize production, increase recovery and maintain production plateau nine years after first oil.
Surviving the Low Oil Price Cycle While Increasing Production Through Best Practices in Workover and Drilling Operations; Case Study of a Marginal Field in Niger Delta, Nigeria
Authors: Atakele Longfellow Oghale , Airhis Osahon Noruwa , Etim Ntietemi Ekpo , Ipoola Fisayo Jordan , Anim John Osadebe , Owieadolor Osa Simon
Published: October 2018

Few companies had the impetus to increase crude oil and gas production to sustain revenue during the recent oil price crisis that rocked the petroleum industry. Multinationals, mid-sized and marginal independent oil companies were all impacted, suspending all field development activities such as drilling, workover, completion and recompletion. How do you survive as a company if you still manage your capital projects in a wasteful manner? What is your company's culture on project management? To efficiently manage your capital projects without creating huge debt for the company, you should have a culture on project management in place. This is one of the critical success factors surviving the low oil price trough ride. It was even more excruciating for marginal independents characterized by low production; high unit operating cost; hostile communities; poor credit rating; frequent pipeline vandalization for theft of oil and near zero economies of scale in projects execution. As a company, we were able to carry on with our field development plan to increase production and consequently revenue during the crisis because we have managed our projects, eliminating wastes even with high oil price through tested project management processes. These processes have been lumped into planning, execution and closing with other critical success factors such as: process ownership, incentive driven performance and smart contracting. The result was an unprecedented ten-million-dollar deviated well in the Niger Delta drilled to a measured depth of 11,000ft and completed dual. A second well was sidetracked with less than eight million dollars from 4000ft to 10,500ft at an angle of 40 degrees and also completed dual. Typical wells in the Niger Delta cost between eighteen million and thirty million dollars but for the systematic approach of a motivated team, huge savings were made at the same time increasing the field production by seventy-five percent. Performance from previous workover have been included in this paper to demonstrate the consistency of our approach to drilling project management.

This paper will help operators especially small independent operators to manage their drilling and workover projects more efficiently to increase profitability bottomline and find their exit from huge debts arising from projects with high capital expenditure (capex).
Slugging in Multiphase Pipeline Systems and Capacity Evaluation of Downstream Reception Facilities
Authors: Akeju Adetokunbo , Agunu Felix
Published: October 2018

Slugging is a transient phenomenon associated with flow instabilities usually in pipeline systems; and can occur principally in one of two ways or a combination of both: (1) hydrodynamic slugs and (2) terrain induced slugs.

A case study is the Ewa field development which involves the drilling and production of up to 5 wells and multiphase export to existing Idu flow station via a 12-inch × 16.5 km pipeline. The pipeline right of way includes road and river crossings, as wells as passage through local farmlands.

The river crossing poses a peculiar challenge as the pipeline will potentially be buried up to a depth of about 60m from the surface (at the cliffy end of the river); introducing the potential for terrain induced slugs in the pipeline system.

It is important to confirm that the downstream reception facilities at Idu, i.e. production separators; have sufficient residual capacity to accommodate incoming slugs to prevent high level trips and process shutdowns; leading to production deferment and revenue loss.

The objective of this paper is to perform dynamic analysis using OLGA software to evaluate the severity of slugging and magnitude of slugs; as well as slug frequencies in pipeline arriving at Idu during normal and pigging operations. The capacity of downstream reception facility in handing incoming slugs is also evaluated.

The results of the assessment are validated with similar analysis performed for existing 10-inch × 4.5 km Davy pipeline to Idu flow station versus field experience.
Coiled Tubing Intervention for the Actuation of Reservoir Formation Isolation Valve in a High-Pressure Gas Well
Authors: Okonkwo Onyinye , Oyeintonbra Imbazi , Okolomma Emmanuel , Ibrahim Yahaya
Published: October 2018

Well – K1 is one of 6 gas wells drilled and completed in an over-pressured gas reservoirs in-line with SPDC aspirations to leverage on the opportunities presented by deep and over-pressured gas plays in a bid to develop hydrocarbon reserves to meet existing gas supply commitments and growing domestic demands (driven by power and manufacturing sectors).

The well sand-face completions incorporated a Formation Isolation Valve (FIV) which provided a temporary isolation of the high reservoir pressure (circa 9,400psi) allowing the safe deployment of the upper completions in a lower density fluid, thus creating a 3,200psi underbalance without the well flowing.

Post well construction and prior to hooking up the well for production, an evaluation was made on the best well intervention method to actuate the closed FIV open, especially because the hydraulic "trip-saver" option of opening the FIV was deactivated during well construction making the mechanical option the only means. After due considerations of the well configuration, high reservoir and surface pressures, high differential pressure across the FIV and possibility of mud solids settlement on the FIV shifting profile hindering access, Coiled tubing (CT) was selected to deploy the FIV shifting tool to mechanically open the FIV.

After many months of careful planning and preparation, the intervention was carried out successfully and the well tested to planned rate.

This paper discusses the detailed job design and planning towards deployment of coiled tubing in a deep over-pressured well. Also highlighted are the key challenges and experiences gained which can be referred to as a benchmark for CT deployment in HPHT environment in the Niger delta.
Optimizing Usari Field Production Through Effective Sand Management
Authors: Ishomo O. L. , Ukanah J. , Itsueli J. O. , Alege F. R.
Published: October 2018

Usari field is known for its sand production history. The first sand production incident occurred in 2001 when a choke had a pin-hole leak resulting from sand production/erosional effect. Since then, produced sand and residual sand in sub-sea pipelines have caused recurrent failures of surface rotating equipment (pumps), frequent de-sanding of vessels and topsides and volumetric downtime (deferred production) associated with total platform shutdown or restricted production.

In the past, sand management and surveillance activities included conducting bucket and screen (B&S) sand checks or sampling on all flowing wells as part of monthly routine well test; utilizing a hydro-cyclone sand trap to conduct comprehensive sand checks on identified sand producing wells and establishing sand free production rates; monitoring wells to ensure they are flowing at established sand free rates; and carrying out periodic de-sanding of surface vessels and topsides.

A step change in the approach to sand management and surveillance in Usari field was implemented in 2009, when a multi-functional team was chartered to develop procedures for Usari startup and post-startup operating philosophy. In addition to existing sand management practices, the team implemented bucket & screen (B&S) sand checks at strategic topsides locations (upstream of the separator and at the main online pumps (MOLP) suction). The team also developed a spreadsheet to calculate sand production rates and established benchmarks for acceptable sand production rates through the MOLPs. The team provided on-site supervision of startup activities and monitored sand surveillance activities through the Asset Level Team (ALT).

Usari field was successfully restored to full production and currently produces at over 120% of post-startup average production. Wells were produced at maximum sand-free rates and disruption to continuous production due to sand-related platform shutdowns were minimized, thereby maximizing value in a sand- prone asset. Post startup, the team continues to provide guidance to field operations, and sand surveillance results are reviewed during ALT meetings.
Achieving World Class Oil Recovery Factors through the Application of Integrated Reservoir Management Best Practices - The Yoho IB1-Upper Reservoir Case Study
Authors: Onoyase Akpevwen , Orupabo Sopreye , Mkpasi Ernest
Published: October 2018

Yoho field is located in the southeastern part of Nigeria, within the NNPC/MPN Joint Venture (JV) acreage. Discovered in 1991 and streamed in 2002, the reservoirs are fault dependent closures and consist of thick upper Miocene, tidal-deltaic deposits with average porosity and permeability of over 27% and ~5D respectively.

The IB1-Upper (CFB) reservoir is one of the three major reservoirs developed in the central fault block and holds about 20% of the field's STOIIP. It was initially developed with four oil producers and one crestal gas injector, with one of the producers later redrilled to a more updip location after it watered-out. As at Year-end 2017, the cumulative oil production from the reservoir was 121 MBO, representing about 70% of the STOIIP. This Recovery Factor (R.F.) is much higher than the average value of 50-60% for reservoirs undergoing similar depletion.

Although natural water influx supplemented by crestal gas injection is the main recovery mechanism, different tools and practices have also been concurrently utilized to continually optimize the depletion plan, predict performance and optimize recovery. These tools and practices include adequate pressure monitoring using Permanent Down Hole Gauges (PDHG) to determine pressure trends and track efficiency of gas injection / ensure efficient sweep, PI Surveillance Data Acquisition System for production optimization, a simulation model using ExxonMobil's EMpower software and a Petroleum Experts Integrated Production Model (IPM).

This paper details the reservoir management practices and programs that were undertaken to achieve the world class recovery factor of 70% in the Yoho IB1-Upper reservoir.
Impact of Integrated Operations Planning in Operations TEPNG-JV District
Authors: Obuotor J. , Iwegbu M.
Published: October 2018

Several ‘mini’ planning existed in the past in some operations’ departments in TEPNG-JV district. These planning were not quite effective as they were neither integrated nor centrally coordinated. There were no structured processes, no structured planning review meetings, no common planning rules and no planning organization. The various disciplines simply worked in silos.

Looking at the title, the questions that might be on the lips of the reader is what is integrated operations planning? What does it entail? What role does it play in day-to-day business of oil and gas production? Integrated Operations Planning is a consolidated, ‘live’ planning that gives a single view on all planned operational activities. It is a decision-making tool used by Top management, Managers, Engineers and Technicians at varying degrees.

It is used in identifying and resolving operational conflicts, optimizing production, negotiating contracts, deciding on SIMOPs (Simultaneous operations) and Co-activities, rig planning, wells interventions planning, budgeting, forecasting short, medium and long term offshore and onshore accommodation needs as well as in the preparation of the yearly reserves evaluation (PRIME) and Long term planning (LTP) exercises.

Integrated Operations Planning (IOP) encompasses all key areas of operations; Drilling, Completion & Well Interventions, Shutdown operations, Engineering (Process, Mechanical, Instrumentation, Electrical, Structural), Construction, Maintenance, Contracts, Procurement, Technical Logistics, Production Technology, Geosciences, Development Planning, HSE, Production, Inspection, Gas business, LNG, Government and Partners Interface.

This planning, which started a few years ago in TOTAL E&P Nigeria (TEPNG-JV District), has been quite impactful, as it has resulted in time, monetary and resources savings. This paper seeks to highlight these impacts.
The Use of Tubing Tester Valve to Optimize Completion Cost and Time
Authors: Ifediora Emmanuel Eberechukwu , Ibrahim Charles , Salami Hassanna , Omagoro Prosper , Babalola Saheed , Ogueli Okechukwu
Published: October 2018

The job of pressure testing the tubing while running in a well was left up to running a standing valve to a nipple profile with a slick line unit. This involved multiple runs to set, test, and pull the standing valves, and with the advent of horizontal well's completion, the completion cost increases as more slick line trips are made. However, in high angle/horizontal wells, the slick-line associated hole problem has become a major challenge because of the inability of the gravity-assisted, slick line run to convey a standing valve to angles greater than 65°. This slick line limitation and associated challenges has resulted to major operators to find a more efficient method to pressure test the completion string.

Various operators have done different things; including pressure testing the annulus of the string/casing to verify the tubing integrity to avoid slick line associated hole problems. In the quest to solve this problem and adding to body of knowledge, Addax petroleum team of engineers introduced a tubing tester valve as part of the completion string and used it to test the pressure integrity of the completion string connections while running in hole. In carrying out a tubing pressure test, the pumping sub with surface lines was rigged up directly on the tubing from the cement pumping unit, and pressure tested. The pressure testing exercise of this string took approximately 40 minutes. Also, to note that the tubing tester valve is a full-opening tester valve that allows completion string to self-fill while running in hole. The completion string could be pressure-tested as many times as required as it is run in the hole.

The tester valve has reduced the rig non-productive time and risks associated with slick line deployments. The tester valve consists of a curved flapper valve and spring, a shear ring and locking dogs that allow the curved flapper to be fully closed during a pressure test; while the valve can be fully over ridden with a higher hydraulic pressure, which then opens a large-internal diameter through valve bore, permitting the internal diameter of the string to an unobstructed production rates and future well intervention access.

The production string pressure test has been successfully carried out in sixty horizontal wells to date. The cost evaluation analysis performed between the slick line standing valve and the tubing tester valve tests for some of the wells shows cost savings as much as $240,000 per well on the jack up rig.
Determination of Most Likely STOOIP Using Hydrocarbon Fluid Contact Tracking in Material Balance: A M-77/CNL Reservoir Example
Authors: Kuku Abimbola , Omotayo-Johnson Mobolaji
Published: October 2018

The use of Material Balance in determining Stock Tank Original Oil in Place (STOOIP) can most often prove to be challenging due to the fact that the material balance equation is a single equation with many unknowns making the solution to the equation inherently non-unique, in other words a range of original oil in place (STOOIP) gives a good match to the material balance equation. This is even made more complicated and challenging in scenarios where there are no defined contacts in terms of Original Oil Water Contact (OOWC) and Original Gas Oil Contact (OGOC) which is used to define the oil column for deriving a volumetric based STOOIP. This creates an uncertainty as to what represents the Most Likely STOOIP or Base Case STOOIP to test various development scenarios.

A good example of this scenario is the M-77/CNL Reservoir which is a saturated reservoir with a Lowest Known Oil (LKO) at 7404ft TVD SS and an Original Gas Oil Contact (OGOC) at -7292ft TVD SS. The reservoir also has an Original Highest Known Water (OHKW) at -7434 ft TVD SS from a post-production well. This invariably creates a 30 ft uncertainty on what can be attributed as the Original Oil Water Contact (OOWC). STOOIP values for such scenarios can range from the Original Gas Oil Contact (OGOC) to the Original Highest Known Water (OHKW) as per Chevron Reserves and Resource Booking guidance regulations which is also consistent with the SPE Petroleum Resources Management System (PRMS). Such variations in STOOIP values can prove problematic especially in cases where deterministic or single point values are required.

This paper demonstrates how the inclusion of Hydrocarbon Fluid Contact Tracking in Material Balance workflow for STOOIP determination helped reduce STOOIP uncertainty and determined what best represents a Most Likely or Base Case STOOIP for the M-77/CNL Reservoir. The overall result of this analysis led to the increase in Reserves booking, update of recovery factors, input into reservoir simulation studies and the identification of an infill drill opportunity for the reservoir which is currently being matured through internal Chevron Infill/ Development well processes.
Case Study Review to Reinforce a Decision-Based Experimental Design Methodology
Authors: Ogbuagu Frank , Silpngarmlers Lynn
Published: October 2018

Design of experiments (DoE) is an industry methodology designed to test the impact of different variables on an objective function without running every single scenario possible. Despite its many advantages, there still exists the tendency to engage in re-work, particularly when the results of the experiments do not align with expected outcomes.

This paper highlights the need for a decision-based approach for DoE studies to eliminate inefficiencies in resource utilization. A decision-based process focuses changes in variables and analyses on those that have the potential to impact the final decision for which the study is being carried out.

A DoE study for a virgin reservoir development, conducted in two run cycles is used to highlight this. For the first cycle, the top variables from stakeholder engagement and initial Pareto and Tornado analyses were carried forward for final runs and analyses. The same was repeated for the second cycle, with a change in the distribution of the key variables, within the limits of analog data available.

The analyses of both run cycles show close alignment of the results of both run cycles. Also, the same development decision was reached from the results of both run cycles, even though changes were made to the input variables for the second run cycle. A review of the Tornado chart for either run cycle shows that the development decision can be arrived at with either one, without the need for the other. This shows that the number of run cycles for similar studies can be minimized to ensure that only those that have the potential to change the decision to be made are carried forward. This will ensure optimum use of the limited available technical, time and computational resources, allowing the professional to do more with less.
Lessons on Team Integration from 2017 Bonga Turnaround Maintenance
Authors: Mustapha Adetoun , Afuba Paul , Enechi Felicia , Ejiofor Chiedu , Olasubulumi Akintunde
Published: October 2018

The most complex and largest Turnaround Maintenance (TAM) in the history of the Shell Nigeria Exploration and Production Company's Bonga asset was completed in April 2017. Strategic value drivers were Statutory/Regulatory, Asset Integrity, Relief Valve(RV) Recertifications, Vessel Cleaning and Upgrades. Often, Turnaround management has huge impact and directly contributes to the company's bottom line profits. However, controlling turnaround costs and duration represent a definite challenge.

This paper presents the structured process of managing the TAM project and key lessons learnt on integration with its attendant impact on project delivery. The turnaround comprises over three hundred Operations, Maintenance and Project scopes. Over ten in-field vessels were deployed, including a 600-bed Floating accommodation vessel, and over 50 Nigerian contractors and sub-contractor companies were involved while over 2,000 material deliveries were required. The workforce was over 1,000 people that cuts across 10 Functions, several Disciplines, diverse culture and mixed genders; and spread across locations. Team effectiveness and integration were identified as key elements for the team to complete the scope safely, within budget and on schedule.

Overall, several challenges were encountered during the TAM; and interventions were implemented to deepen end-to-end thinking, make performance on integrated key performance indicators visible and rally the teams to get critical steps right. This paper shares learnings on how the team was orchestrated to develop shared goals, common understanding of processes and appropriate behaviours and work effectively across organizational boundaries as ONE team. The critical scopes were delivered on schedule and below budget. The TAM therefore resulted in increased asset reliability, continued production integrity, and significantly reduced the risk of unscheduled outages or production deferments.
Comparative Study of Sand Control Methods in Selected Niger-Delta Sand Stone Reservoirs
Authors: Aroyehun Mojisola E. , Oko Francis. N. , Onyeanusi Obinna , Oguntade Tomiwa , Kabara Auwalu , Dimkpa Benson
Published: October 2018

Sand production is one of the major profit hurting occurrence in Niger-Delta sand stone reservoir which must be managed within permissible limit to avoid potential risk to environment, equipment and hydrocarbon recovery. Uncontrollable production of sand reduces reservoir performance and increases operational cost. The utilisation of sand control devices and reactionary approach for sand management most time exacerbates production loss. Hence there is the need for understanding the concept and selection criteria for appropriate sand control methods and devices in Niger-Delta sand stone reservoir.

This paper presents performance study on selected sand stone reservoirs in Niger-Delta field AAA operating with difference type of sand control mechanisms such as internal gravel pack (IGP), sand consolidation using chemicals (SCON) and Cased Hole Expandable sand screens (CH-ESS). Hence determining the key parameters that influence production from the unconsolidated sand stone of Niger-Delta sand stone reservoir.

The results show that the well completed with IGP produced at longer plateau rate and within permissible sand production limit than other methods presented, though the performance is less efficient in deeper interval than in shallow interval. Also the well completed with IGP is more efficient either in high or low drawdown scenario while well completed with SCON experiences high sand rate and early water breakthrough with increase in drawdown. The grain size distribution and the bean up programme at initial start-up have been identified as key factors that influence recovery, selection and durability of sand control mechanism. The results from this work will provide guidance in selection and management of sand control systems in future developments in AAA field and other Niger Delta formations.
Comparative Analysis on Rate Dependent Polymer Flooding Using Bio and Synthetic Polymers
Authors: Abdulraheem Madugu , Hamisu Tukur , Abdullahi Gimba , Oluwaseun Taiwo , Kelani Bello , Mohammed Ismail , Olalekan Olafuyi
Published: October 2018

Polymer play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to their critical importance of mobility control in achieving high oil recovery. This high oil recovery is dependent on polymer properties and the rate of flooding.

This paper presents the results of polymer flooding of an unconsolidated porous media using the locally available Gum Arabic in its natural and Modified states. Commonly used polymers Xantham Gum and Hengfloc were also used for comparison. The effective flooding rate was established using Modified Gum Arabic as the polymer. The established flow rate was used in polymer flooding for other polymers. Different concentration of each polymer was used to achieve similar viscosity of polymer solutions used for each flooding. The brine, oil and porous media properties were also kept constant.

The results from these studies favoured a low injection rate. More oil up to 90% of original oil in place was recovered. The result from the oil recovery using the established effective rate on other polymers showed that the Modified Gum Arabic recovers approximately 10% more than the natural Gun Arabic, Xantham Gum and Hengfloc. The recoveries were 90.2%, 81%, 79.5% and 80.2%, respectively.

It was also observed that the oil retention time in polymer mixture is lower in Modified Gum Arabic and Natural Gum Arabic when compared to Xantham Gum and Hengfloc.
Determination of the Degree of Contaminants of Different Refined Products From Kaduna Refinery
Authors: Egu Daniel Ikechukwu
Published: October 2018

Contamination of petroleum products at source has been a major setback in the downstream in Nigeria. Several mechanical crashes in the air, roads, and water ways have also been traced to cases of possible contaminated refined petroleum. There are no enabling laws to prevent these excesses. The aim of this study however, is to carry out a detailed simulated experimental procedure using different percentages of petroleum products from the Kaduna refinery as contaminants. The objective is to conduct several laboratory tests on the product sample for traces of mixtures with other products, in order to establish possible cases of unintentional contamination during handling at the refinery, to mix several products together and test for the possible traits from the mixture as well as the effect of such trait in the containing fuel and to determine the degree of contaminants in each of the mixture and to what extent it influences the individual characteristics of each product present in the mixture base on the degree of contamination. Materials used are PMS, AGO and DPK. They were contaminated with 85%, 90% and 95% of each product. Results show that for 85% DPK with 15% AGO had the highest SG at 15/4°C. This blend also had the highest distillation IBP at 175°C and EBP at 328°C with a flash point of 62°C, the cloud point, viscosity, colour and sulphur content were not recorded. For 95% DPK with 5% PMS had the highest SG at 15/4°C, distillation IBP at 95°C and EBP at 248°C, it has no flash point because PMS is very volatile, the cloud point, viscosity, colour and content were not recorded. The same procedure was applied for all the samples and compared with results from a few dispensing stations in Kaduna with some variation of impurities. It is recommended that handling of petroleum products and particularly the blending processes in our refineries should as a matter of fact be very thorough with proper re-examination of products using appropriate laboratory procedures before dispensing them to the public.
Laboratory Foamed-Cement-Curing Evolution Using CT Scanning: Insights From Elevated-Pressure Generation
Authors: Dalton Laura E. , Brown Sarah , Moore Johnathan , Crandall Dustin , Gill Magdalena
Published: October 2018

Computed-tomography (CT) scanning has become a mainstay among scientists (Wildenschild and Sheppard 2013) because it enables nondestructive observation of material processes and formation in real time. Foamed cement is a high-strength, low-density material containing nitrogen gas, and is used to stabilize wellbore casings both onshore and offshore. In-situ foamed cement is subject to pressure changes because the slurry is pumped downhole and cures at depth. To correlate the influence of pressure to the gas-void size and the curing evolution of a foamed cement, two laboratory foamed cements were generated and CT scanned as they cured. One cement was generated following the American Petroleum Institute (API) industry standard API RP 10B-4 (2015) at atmospheric conditions using a blender, and the other cement was created using a foamed-cement generator (FCG) (resembling that of de Rozières and Ferrière 1991) to produce a sample at an elevated pressure. FCG-generated cement qualities (in the range of 20, 25, 30, 35, and 40%) were scanned at their cured state for comparison. From the CT-image time series and the single FCG scans, the volumetric void properties were characterized and compared. The time-series blender voids were an order of magnitude larger than the FCG voids, and void growth was stagnant after a curing period of 100 minutes, whereas the FCG voids gradually increased in volume after 100 minutes. The Hsü-Nadai plots (Brandon 1995) reveal that the FCG and blender voids are weakly prolate, and all FCG voids, regardless of generation quality, relax to a greater final-magnitude strain than the blender voids. These findings confirm that both the void size and the curing process are influenced by the pressure at which a foamed cement is generated.