bluuebunny/crossref_metadata_2025_split huggingface dataset:
WRFM Technical Data Management - An Enabler for Effective WRFM Value Loop Excellence
Authors: Kingsley Iheajemu , Thomson Attah , Kalu Igban , Babatunde Adeniran 
Published: July 2016

Abstract
Most operating units, including Shell Companies in Nigeria have faced increased pressure to provide quality information timely and more efficiently for effective business decision-making. One of the most fundamental assets of a company is understanding the value of data and the knowledge it creates.
Data quality improvement involves several factors, they include, but are not limited to: a technical understanding of data source;understanding data gathering processes; and having people with well-defined roles, responsibilities, and authority to develop a culture that supports data quality improvement. As such, the majority of assets in different countries need a consistent and standardised approach in managing their Wells, Reservoir, and Facility Management (WRFM) technical data.
The WRFM value loop is a conveyor belt of data into opportunities that are executed to add production and reserves, therfore all the segments of the value loop need to be effective. Data management as an integral part of the value loop is one of the mandatory minimum requirements set out to support WRFM excellence.
The need for quality data which has led to data standardisation efforts enforcing rigorous plans within WRFM assets has to a large extent tackled lingering data issues ranging from;Technical data inaccessibilityDiscipline data ownership issuesData quality and inconsistency andLost time spent on data search, revalidation and rework, etc.
A series of Technical Data Management (TDM) initiatives were implemented to include the use of; Data Atlas, standard WRFM Technical Data Management plan which supports the WRFM programme by defining data stores, retrieval workflows, data quality requirements, roles and easy access to all WRFM critical data and the WRFM Critical Data Catalog, among others.
These technical data management initiatives have been effective as is evident in Data Management ratings and scores at recently concluded external WRFM assessments thereby supporting five Shell Petroleum Development Company (SPDC) assets to achieve world-class status passing minimum standards.
Also, generally in Shell Companies in Nigeria, proper management of access control measures, data security classification, data archiving and retrieving yielded reduced time spent by data users over the years by 37%, enabling additional barrels with efficiency gains and timely decision making.
This paper therefore highlights the benefits of TDM in WRFM processes, as a key element in the WRFM value loop, providing trusted data at the fingertips of engineers and geoscientists alike.
Case Study of Unitisation and Joint Development of Straddle Fields in Nigeria
Authors: Egba Amba Ndoma , Bekee Emmanuel , Oriaifo Maynard , Dosunmu Adewale 
Published: July 2016

Abstract
Hydrocarbon accumulations more often than not straddle two or more license areas or concessions and sometimes, international boundaries. Unitisation is a process whereby petroleum reservoirs (fields) straddling concession boundaries are developed and exploited as a unit using a single operator (the Unit Operator) and common production facilities under a signed agreement (Unitisation Agreement), by the holders of the respective concessions. The objective is to maximise economic recovery of producible hydrocarbon. In Nigeria, the enabling law that gives legal backing for unitisation is the Petroleum (Drilling & Production) Regulation 1969, Section 47, as amended and the 2008 Unitization Guidelines by the Department of Petroleum Resources (DPR). These laws are made pursuant to the powers conferred on the Minister of Petroleum Resources under Section 9 of the Petroleum Act (CAP 350) laws of the Federation of Nigeria 1990.
One of the major milestones in the unitization process is the signing of the unitization and unit operating agreement (UUOA). The UUOA specifies how the straddle field is to be operated and defines tract participation (the equity interest, assigned to each Concession in the Unit). As at today, over seventy (70) straddle fields have been identified in Nigeria but not up to five (5) UUOA agreements have been executed. Issues ranging from correct interpretation of Regulation 47,recognizing unitization of straddling and non-straddling reservoirs, to single and combined provisional tract participation (PTP) for oil and gas, economic consideration & contractual disputes, fiscal terms, Redetermination, Reference dates, appointment of unit operator, funding, divestment, political and personal interest etcetera, have made unitization of straddle fields elusive for many years thereby locking down billions of barrels of reserves. This undoubtedly, is not in the national Interest, especially when the Country is striving to increase the Nation's reserves base from the current 36.24 barrels of oil to about 40 billion barrels and the daily production output of 2.5 million bopd to 4.0 Million bopd by year 2020.
This paper therefore examines the synopsis of unitisation and joint development of straddle fields in Nigeria, the concerns and pitfalls arising thereof. The evaluation of some selected cases is also made to ascertain the effect of delay from Government objectives of reserves addition and production along with suggestions for future policy formulations.
Modelling Wellbore Stability by Chemical Method in Niger Delta: A Review
Authors: Okafor I. S. , Joel O. F. , Iyuke S. E. , Ndubuisi C. E. 
Published: July 2016

Abstract
Drilling through shale formation can be challenging and sometimes results in wellbore instability problems due to the reaction between hydrophilic shale and drilling fluids. The typical low permeability of shale, the presence of ions and charged surface of the constituent clay are factors which makes the problem of wellbore instability very complex despite efforts dedicated to the study by researchers. The study of wellbore stability in shale is quite important because 75% of all formation drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations costing the industry more than $1 billion USD/year (Chenevert, 2002; Zeynali, 2012); the lost time due to this challenge also account for over 40% of all drilling related non-productive time (Zhang et al, 2009) and these instabilities are responsible for 10-20% of the total drilling cost. A solution through this challenge is critical to the sustenance of the investment made by operating companies in the oil and gas industry. This will drastically reduce drilling cost, completion and workover cost as well as the accompanying downtime involved. It will also improve the net present value of operating company in the industry. Basically wellbore instability occurs when the mechanical stress induced by drilling into the formation exceeds the formation rock strength. Chemical interactions between the drilling mud and the in-situ shale affect the in-situ stress state of the formation hence the stability of the formation. Geo-mechanical models have been designed to tackle mechanical wellbore instability in the Niger Delta the challenge therefore is a chemical solution to the wellbore instability problems of the region. Oil-based muds have been known to overcome wellbore stability problems, but disposal challenges and environmental concerns have led to infrequent use. The challenge therefore is to formulate an environmentally friendly drilling mud having the inhibitive properties to tackle the wellbore instability challenges. This paper presents a review of studies carried out to characterize the mineralogy of shales and the salinity distribution of formation water in the Niger Delta depobelts with a view of designing a "balanced-activity" drilling fluid to help stabilize the formation during drilling. Results obtained from the reviewed researches showed that shale mineralogy characterization and formation water salinity distribution is critical in designing a balanced-activity drilling mud that can effectively tackle the problems of wellbore instability.
A Systematic Approach to Intelligent Well Performance Modelling Using IPM Suite
Authors: Edih Michael , Nnanna Erasmus , Nwankwo Cosmas 
Published: July 2016

Abstract
Intelligent well technology use Inflow Control Devices (ICDs), Inflow Control Valves (ICVs), and measurement devices that provide opportunity for monitoring and control of production from different reservoirs from the same wellbore. The common value drivers for the deployment of intelligent wells include reduction in well count during field development; accelerated ultimate recovery (UR); and accelerated production. Efficient and accurate modelling is therefore critical for the realisation of the full benefits of intelligent wells in addition to other technologies like the use of geochemical finger printing.
In this paper, a simple workflow for modelling the performance of intelligent wells is presented. This workflow identifies the limitation of current standalone PROSPER model and provides a window to easily match the model to actual well test results, providing multiple calibration points and ensuring full utilisation of the data made available by the intelligent well accessories like the permanent downhole guage and downhole flowmeter. The workflow has been applied to carryout nodal analysis of both oil and gas completions in the Niger Delta, Nigeria.
The modelling workflow is divided into two (2) aspects – the inflow modeling, for each inflow zone, and the outflow modelling that captures the commingled production. The commngled outflow model is used to generate the lift table for the GAP model.
The well deliverability and PQ curves are generated and plotted using the Openserver utility in IPM, which can be used also to view the performance of the model against validated well test results.
Results of applying the workflow to two case studies in the Niger Delta were analysed. The model was used to predict the expected performance of the wells at different surface choke sizes and ICV settings. The model results (flow rate, flowing tubing head pressures, flowing bottomhole pressures) matched closely (with maximum of 10% deviation) with the actual measured results, confirming the accuracy of the recommended workflow.
Reservoir Properties Distributions in A1000 Geologic Models for Optimal Drainage, Onshore Niger Delta
Authors: Afuye Taiwo 
Published: July 2016

Abstract
The interpretation of depositional environment and the reservoir properties, properties modeling and property prediction for field development planning are characterised by subsurface uncertainties. There are reduced wells data and absence of core data for the derivation of estimates of subsurface parameters; which form input to the process of populating trends to constrain the extrapolation of properties which increase these uncertainties.
An Areal Geological Concept; 2D Trends (Probability) Map of the A1000 Reservoir was built based on the geological interpretation of the depositional environments as interpreted from the well logs, provides areal coverage for the models. The 2D Trends Map generated was used to guide the extrapolation of reservoir properties away from well control/coverage. The Stochastic approach uses Sequential Indicator Simulation (SIS) and Sequential Gaussian Simulation (SGS) algorithms in PETREL Modeling software for building the facies and petrophysical models respectively and as well, incorporating this 2D Trends Map and tested Modeling parameters, such as variograms, kriging, cell sizes, zones, and to determine which set of parameters ultimately produced the most geologically reasonable model of the A1000 reservoir thus minimising the subsurface uncertainties.
The results of the properties models show that regions showing good facies, higher porosity, higher permeability, lower shale volume, lower water saturation values of the A1000 reservoir as optimal location for development wells placement from the static modeling perspective.
Quality Check Tests show that reservoir properties models built are consistent and honoured the geological interpretation of the depositional environments. This approach will enable optimal development well placement, Stock Tank Oil Initially in Place (STOIIP) estimate and eventually leading to successful dynamic Modeling of the reservoir.
Usan Field: Maximizing Production from New Drillwells in a Hydraulically Constrained Deepwater Subsea System Using IPM suite
Authors: Oguchi Arinze , Remi-John Babatunde , Okonkwo George 
Published: July 2016

Abstract
Usan, a deepwater field located offshore of Nigeria, commenced production in February 2012 with development drilling to be completed in 2016.
The field has 2 subsea flowline loops with 4 risers giving the flexibility to flow wells through two different risers. Due to the constrained flowline capacity, optimization of well routing and drillwell sequencing became critical to sustain the remaining drillwell campaign while maximizing base production and incremental uplift. The adopted approach by the Production and Reservoir Engineering teams was to utilize the Integrated Production Modelling (IPM) software suite (PROSPER, GAP & RESOLVE) to ensure optimal well mix and flow stability.
A systematic approach of continuously testing various routing scenarios of wells within the different production loops was applied to minimize production back out loss due to system hydraulics during the streaming of new drillwells. Different ramp-up scenarios were also tested for the new wells to minimize back-out on base wells. Due to variations in fluid properties, reservoir pressures, depletion strategies and loopline distance, the system needs to be re-evaluated frequently. With over 50 routing sensitivities assessed at each evaluation, identifying and implementing the optimal routing/configuration became critical.
Production optimization using the IPM model has led to higher FPSO incremental rates from new drillwells due to optimized well routing within the production risers. This has also helped to sustain the ongoing drilling campaign in the Usan field and improved the economics of the overall project.
This paper describes how IPM software was used to maximize incremental production from new drillwells.
Usan Field: Managing Gas Injection at Mechanical Seal Capacity
Authors: Oguchi Arinze , Okonkwo George , Sarumi Oluwatoyin 
Published: July 2016

Abstract
Usan is a highly-compartmentalized deepwater field offshore Nigeria with both structural and stratigraphic barriers across and within the compartments. The reservoirs were at their mechanical seal capacity based upon evaluation of reservoir and leak-off pressure trends. This complicates gas injection and pressure maintenance in the Usan field.
Due to the lack of gas export channels, gas injection was adopted as part of the development plan for the field in addition to water injection. During the first 18 months of production, less than 40% of produced gas was reinjected due to reservoir pressure/leak-off constraints.
A gas injection strategy was developed based on a number of uncertainties which included actual crestal depth, fracture pressures, and communication within and across compartments. To maintain or increase gas injection, the team needed to establish reliable crestal depths for each compartment, define safe injection pressure for each injector, and effectively monitor the pressure response of the reservoirs to ongoing gas injection.
A novel approach was used in better determination of the crests using fracture and fluid gradients. Safe injection pressures were based on dynamic injection pressures rather than static reservoir pressure. With these estimated crest depths and fracture pressures for the gas injection compartments, volume-depth curves were used to determine gas column height and safe injection pressures were calculated for each gas injector. Due to the mechanical seal integrity concerns, a monitoring system was developed to avoid the risk of fracturing the reservoir with continued injection. The surveillance strategy utilizes real-time flowing well pressures, short duration shut-in pressures, and evergreen volume-depth curves.
Ultimately, managing reservoir pressure levels and trends in each compartment allowed for increase in overall gas injection in comparison to previous methodology. A 30% increase in gas injection rate was immediately achieved. Optimal gas injection has also been maintained resulting in improved oil recovery.
This paper focuses on the methodology of determining/applying safe gas injection targets and maximizing oil recovery within the known constraints and uncertainties.
Fiscal Policies in Oil and Gas Sector: Quantitative Assessment of Impact of Royalty Terms on Proved Reserves Estimation
Authors: Ikwan Ukauku , Dosunmu Adewale , Iledare Wumi 
Published: July 2016

Abstract
Petroleum Fiscal Systems refer to the arrangements between a host government and an oil and gas exploration and production company to explore, develop and produce hydrocarbons. Royalty term is a key element of any petroleum fiscal policy and it could be fixed-by-terrain or sliding by volume and petroleum price. Nigeria like most countries operates a fixed-by-terrain royalty system. The defects of such a system include negligence of the size of the firm and the price of hydrocarbon in determining royalty terms. This is attended by negative shock on profitability of small firms and their operations on the one hand and the take statistics of the host government on the other. For example marginal field operators find it difficult to operate under fixed-by-terrain royalty system. All previous investigators on fiscal terms have focused quantitative evaluation on impact of fiscal terms on profitability indicators vis-à -vis impact on government and contractor take statistics without extending to proved reserves impact. This paper fills this gap.
This paper focuses investigation on quantitative analysis of impact of variable and fixed-by-terrain royalty terms on proved reserves using an archetypal onshore producing oil and gas asset, existing royalty term in Nigeria as well as the archetypal sliding royalty terms in Nigerian 2012 draft Petroleum Industry Bill. A proved reserves economic spreadsheet model based on SPE Petroleum Resource Management System (PRMS), sliding and fixed royalty systems was developed and used for the study.
The investigation shows that with two-tier sliding royalty system (based on volume and oil or gas price) impact on proved reserves could be positive, in effect meaning less exposure on proved reserves in existing assets than under fixed royalty term. Also under a period of global low oil price like in late 2014 to early 2016 where oil price has dropped by close to 250%, the firm may have positive effect on proved reserves due to reduced royalty payment used in economic limit test analysis. These conclusions should guide policy makers and negotiators in deciding royalty terms in fiscal policy formulation.
Structural Well Integrity – Surface Casing Corrosion Management Strategy North Sea Experience
Authors: Benjamin Ajaraogu , Taylor Ian , Bakker Eelco 
Published: July 2016

Abstract
Structural Well Integrity is an emerging area in Well Integrity Management in the oil and gas Industry. A key component that ensures the structural integrity for wells is the surface casing.
However, over the years little or nothing has been done to address corrosion problems of the surface casing. Though a number of reports have been completed that analysed the casing failures with recommendations for monitoring and maintenance of affected wells, surface casing corrosion has remained an issue with many operators globally.
The loss of casing wall thickness due to corrosion (Microbial, Oxygen and acid) can lead to collapse of affected wells with attendant loss of production, environment concerns from resulting spills, loss of lives, significant remediation cost and reputational damage. With recent failures of the surface casing due to corrosion and the need to extend the end of field life, a campaign was embarked on to develop an industry-acceptable management strategy.
This paper discusses the integrated approach employed to understand the problem and develop management strategy. The objective of the strategy developed is to implement a management system that ensures that structural integrity of the surface casings of the operators' well portfolio is maintained in line with the well life extension requirements. Effort was made to trace the history of surface casing corrosion within North Sea; review results from surveys of the surface casing; review the calculated risks associated with structural integrity of surface casings for all sample wells; develop workflow for corrosion management; and document monitoring and mitigating measures.
Lessons Learned from Drilling a High Pressure Well in the Niger Delta
Authors: Akinfolarin Ayodele , Erinle Adeyemi , Awe Sunday , Amah Obinna , Ibrahim Timothy , Roes Vincent , Obanya Phillip , Akhideno Mathias , Ugwu Celestine 
Published: July 2016

Abstract
The objective hole section of a High Pressure (HP) well in the Niger Delta was designed to be drilled with Managed Pressure Drilling (MPD) technology. While drilling the well, a significant well-control incident occurred; subsequently the well was redesigned to be drilled conventionally. This paper presents the drilling of the well before the well-control incident; the redesign of the well after the well-control incident; and the eventual drilling of the well to secure the primary objective. The overall intent of the paper is to share the learnings acquired during this sequence of activities. The redesign after the well-control incident involved splitting the objective section in two intervals. This enabled the well to be drilled without compromising the primary objectives, which were data acquisition and an eventual completion on one of the objective sands. The paper also contains the strategies used in the management of the narrow margin between pore pressure and the fracture pressure of the well, without MPD assistance.