bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measurement of the Wax Appearance Temperature of a Gas Condensate Using High Pressure Microscopy Technique
Authors: Mmata Bella , Onyekonwu Mike 
Published: October 2018

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.