bluuebunny/crossref_metadata_2025_split huggingface dataset:
Changing The Dynamics of Performance Management - The Micro KPI Concept
Authors: Benyeogor Ogochukwu , Majekodunmi Ayodeji , Ivan Ambakederemo , Charles Ibeku , Eze Nnadozie 
Published: July 2016

Abstract
The current volatility in the oil and gas sector underscores the importance of delivering consistent top quartile performance. To remain competitive, a robust performance management plan prior to drilling is key to successfully completing the project in time and under budget. Key Performance Indicators (KPIs) have historically been used to evaluate well construction performance. KPI targets are set to evaluate cost, time and quality of drilling operations.
In The Shell Petroleum Development Company (SPDC), a benchmark method using the actual regional average performance data of similar wells drilled in the African region is used to generate high-level KPI targets (Macro KPIs) in terms of cost and time for ‘dry hole’ drilling. This method is recognised globally for target-setting and provides inputs used in forming a business plan. However, the use of Macro KPI targets to communicate performance requirements at the wellsite has been observed not to be as effective as required, since it does not clearly articulate performance required at the micro task level. It also does not allow effective real time monitoring of daily wellsite activities, making traditional performance monitoring retrospective.
Micro KPIs are measures of smaller, repetitive actions that when added up, contribute a significant proportion of the time to drill a well. Breaking each phase of the drilling project into Micro KPIs (Tripping time, Running Tubular, BOP Testing and Handling, BHA Handling etc.) easily shows what it takes to win; what the sources of competitive advantage are; and what drives value. In order to make the transition from Macro to Micro KPI-based performance management flawless, the challenge of standardising Micro KPI target-setting needs to be addressed. This paper builds on the traditional performance management process, and by leveraging existing benchmark data, presents a process of generating and setting Micro KPIs for the drilling phase in an empirical and replicable manner.
Improved Short Term Oil Production Forecast – Application of Well Decline Rates to Generate Field Decline Rate
Authors: Jaja Adagogo J. , Oguntona Bayo , Eme Vincent 
Published: July 2016

Abstract
Overtime the reliability of production forecast had been a major challenge in the oil industry. Reliable production forecast is critical part of planning and decision making in the oil and gas industry. Only about 45% of production forecast meet its target rate and reserves. With oil prices fluctuation there is huge value to be created in production forecast numbers that are reliable for business plan purpose.
Area A has wells under natural production, artificial lift (gas lift) and reservoirs under waterflood. The field historical oil production span over 50 years. Clearly there is need for reliable production forecast for business plan for these matured fields.
Up to 2011 field decline rates (determined from field decline curve analysis (DCA)) and the current production rates were used for production forecast. The use of this method showed actual oil production outside the forecasted production range at the confidence level of P10 and P90. To improve the production forecast reliability to be within the range of confidence level of P10 to P90 the methodology was reviewed and a new method was proposed to determine the field decline rate using roll-up of well by well decline rate by statistical method and incorporate uncertainties in the production start rate range.
This paper will share the applicability of roll-up well by well decline rate to determine field decline rates used for a reliable production forecast range confidence level (P10, P50 and P90) for short term business plan by incorporating the uncertainties from known historical planned and unplanned downtime. The result from this method showed improvement in production forecast by actual production always within the range of P10 to P90 in the last three years.
In-Fill Drilling in Deepwater GoG Development: A Systematic Approach to Collision Avoidance
Authors: Alaekwe Ewelike 
Published: July 2016

Abstract
Today, directional drilling, with no doubts, has brought massive benefits –ultimately has helped to increase reserves, increase production with even fewer number of wells, reduce cost, reduce footprint and environmental impact.
With its enormous benefits also is a risk –the risk of well collision. With the advances made in directional drilling and wellbore surveying the probability of occurrence has been reduced significantly and both service companies and clients have come up with policies to ensure that the risk is kept at ALARP.
Today, three parameters are widely used for collision risk assessment: separation factor, minimum separation distance and centre-to-centre distance. There are different methods used for calculating these parameters and the minimum acceptable value are defined by clients and directional drilling service companies.
The deepwater (GoG) development under review in this paper was developed using the subsea production manifold system. The wells were drilled and tied through a jumper to the manifold; each manifold has six slots. This implied that for every manifold, at least six wells will be closely spaced and thus posing the risk of collision especially during tophole and surface hole sections.
However, at the initial development plan, the well trajectories have been optimized to ensure there were little or no collision concerns as defined by the company rules on what is minimum acceptable separation factor and minimum separation distance. So deploying directional drilling technologies and high accuracy wellbore surveying tools, the initial wells were drilled without any collision concerns.
However, 6years after the first oil, the asset management team has asked for in-fill wells in a drive to increase production and improve recovery. This brought with it special collision concerns; special because these wells are in production and are all tied to an FPSO. Any collision incident will be very catastrophic.
This called for a thorough planning and a more systematic approach to ensure that the in-fill wells are drilled without colliding with existing wells. This paper is aimed at highlighting the systematic approach used to manage this inherent collision risks from the planning to execution of these in-fill wells. A total of 8 in-fill wells have been drilled successfully without any collision.
The success of the systematic approach is largely from the synergy built amongst the client, the drilling contractor, the directional drilling and surveying company in developing and implementing it. At this point, it this has been proven that collision avoidance is not just about solving equations and making calculations (in fact there are different methods for calculating the three defining parameters) but a systematic procedure that must be put in place from the planning, execution to post-execution.
Focused Ingenuity Accelerates Production
Authors: Olayomi A. J. , Ogidi E. O. 
Published: July 2016

Abstract
In early 2003, NNPC/Chevron Nigeria Limited Joint Venture swamp production had grown to over one hundred thousand barrels per day of oil and associated gas and water. However, all operations ceased in March 2003 as a result of civil unrest and security concerns. Production was fully suspended and all field personnel were evacuated. Subsequently, many Swamp facilities and flowlines were severely damaged, rendering all Swamp Assets inoperable.
In 2004, a dedicated cross-functional team began work to restore full swamp operations resulting in ramping up of base production to over fifty percent of the shut-in production within 2 years primarily due to successful execution of three key re-entry strategies.
Re-establish a secure operating environment. Restore production through a phased re-entry approach, building on successes and lessons learned. Applying ingenuity to accelerate production.
This paper will discuss the focused ingenuity and associated best practices employed in 2004 and also the lessons learned that have accelerated a Nigerian Swamp Field production, while ensuring prudent reservoir management is maintained.
Some of the best practices to discuss include:
The establishment of a cross-functional team to manage re-entry activities Establishment of the Global Memorandum of Understandin (GMoU) Continuous scenario planning with key stakeholders to ensure doable contingencies are matured and can be readily implemented Novel application of technologies such as first application of multiphase flowmeters for well testing and production optimization and integration with permanent downhole gauges pressure data to meet regulatory requirements. Ingenuity in field and project management that consistently delivers incremental benefits.
This paper will also review some of the challenges encountered and the steps taken to overcome them and ensure a secure operating environment through a robust community engagement program.
A Nonlinear Flowing Material Balance for Analysis of Gas Well Production Data
Authors: Molokwu V. C. , Onyekonwu M. O. 
Published: July 2016

Abstract
This paper discusses and evaluates a fast, reliable and conservative method of estimating the gas initially in place; reservoir properties—permeability, drainage area and skin for volumetric dry-gas reservoirs using a nonlinear flowing material balance and in the absence of a representative average reservoir pressure history.
This approach uses reliable pseudopressure-normalized rate (PPNR) vs. pseudopressure-normalized cumulative production (PPNC) data. In theory, it considers a pseudopressure-normalized (PPNR) rate vs. pseudopressure-normalized pseudocumulative production (PPNPC). A modification to existing theory is to use a pseudocumulative production function, a polynomial which accounts for variations of the viscosity-compressibility product with fractional recovery. This function transforms the flowing material balance to a nonlinear equation. Pseudosteady-state data are used and matched by polynomial regression on spreadsheets to obtain the various coefficients of the nonlinear equation. The production characteristics are then inferred from the constant and the coefficient of the unit exponent. The 3rd and 4th degree nonlinear equations have shown to give excellent results based on the depletion characteristics of the reservoir. This theoretical-empirical approach can easily be adopted in production data analysis and will predict reliably whilst ensuring a reduction in production data noise and the rigours of digital type-curve matching. We demonstrate the application of this method using simulated and field production data.
Case History - Metal Expandable Annular Barrier for Zonal Isolation in Challenging Cement Operation in West Africa
Authors: Bagal Joseph , Dulic Almir , Onadeko Olugbenga 
Published: July 2016

Abstract
It is well recognized that a failed isolation can have detrimental consequences on HSE, well productivity, and life of the well.
This paper presents the case history of a metal expandable annular barrier used to provide cement assurance via a hydraulic seal in a challenging side-tracked well in West Africa. The initial well was shut in shortly after being brought on production due to excessive precipitation of scale. Investigations identified a shallow formation separated from the production zone by a thin shale section, and prompted questions on the effectiveness of the cement across the production casing. The metal expandable barrier was then selected to assure sealing in the side-tracked well. Two barriers were mounted on the 9-5/8" casing and deployed through the milled window. Following the cement operation, hydraulic pressure was applied to expand rapidly the sleeve bodies in wet cement and set against the 12 ¼" borehole thereby creating an impenetrable seal. The sealing was ultimately confirmed by the absence of scale during production compared to the previous experience of shut-in after only 18 hours of production.
The barriers are seal backed stainless steel sleeves. The expansion process increases the differential pressure capabilities of the packers due to work hardening of the metal sleeves. This also provides a high degree of anchoring. The barriers are full-bore, highly customizable, and are tested ISO14310. The application was for cement assurance but this technology is also applied as zonal isolation in cement-less completions. The metallurgy allows the packer to shape fit into either an open hole with irregular geometry or inside a casing to preclude annular pressure build up by giving a life-of-well reliable seal. Stopping migrating fluids behind pipe has become a critical HSE issue to the industry.
The application of this technology allows preventing loss of life and resources.
Onshore Condensate Well Production Testing and Analysis: A Tool for Optimal Reservoir Management
Authors: Agbaka O. O. , Dala J. A. 
Published: July 2016

Abstract
Considering that well test is an asset evaluation tool, condensate well testing is designed to address the uncertainties in retrograde performance with respect to various flow regimes under certain completion strategies and surface facility design. Condensate banking/trapping around the near wellbore due to liquid dropout (heavy end fraction condensation resulting to high reduction in effective gas permeability), the desire critical condensate saturation to re-establish mobility, the effect of interfacial tension and the capillary pressure present between the immiscible fluids can be observed and possibly addressed from well testing and analysis. A designed pressure scheme suitable to reduce productivity losses is adequately advisable from well test. Well test (which is a variation in sand phase pressure with time) can be used to determine: the dynamism in rock and fluid properties, underground withdrawals and cash flow. It could also serve as a factor for joint venture agreement and sale/purchase of assets. These achievements are based on excellent reservoir/well management initiated by accurate performance interpretation and forecast. The discussion of this paper is centered in the use of production testing and analysis for enhance condensate reservoir/well management.
Various evaluation criteria's (Reservoir Deliverability, Well Productivity and Completion Strategies) were deployed in the characterization of the reservoir/well performance using simulated field data. However, back pressure, process facility design, surface data recordings and sample analysis under selected surface operating conditions were used to simulate the well stream process.
This research has been able to shown that: production well testing and analysis can be used to determine the maximum attainable drawdown that will increase production and delay condensate liquid dropout around the wellbore. The similarities and variations in the results obtained from Maximum Efficiency Rate (MER) test and Bottom Hole Pressure (BHP) test as regards the aforementioned criteria's considering condensate behavior and the necessary maintenance (pressure, completion, wellhead etc) that will be required to sustain and/or improve production performance has been discussed.
Harnessing Reservoir Heat Using Nanofluid Flooding to Bypass Wax Production
Authors: Obode Elizabeth I. , Ifalade Juwon 
Published: July 2016

Abstract
Wax production has been a major problem of crude oil production in the Petroleum industry. Its formation is very undesirable as it clogs pipelines and considerably reduces rock permeability and oil recovery.
Conventional methods of wax involve heating pipeline at intervals to melt the wax or treating the produced crude using dewaxing agents. However, these methods are sometimes expensive and are unable to take care of wax deposited along the tubulars in the subsurface.
This paper seeks to prevent wax production by ensuring that the produced crude remains infinitesimally close to reservoir temperature at every point from the production point downhole to the separator.
The methodology involves sending in nanofluid through the oil column.
Nanofluid is a mixture of nano (10−9) sized metallic particles and a base fluid of choice mixed using a two-step method that ensures that the nanofluid is mixed to a good consistency.
As the nanofluid interacts with the reservoir, it is brought into thermal equilibrium with the reservoir. As both nanofluid and oil flow to the surface, the nanofluid keeps the oil in thermal equilibrium with itself.
Heat loss along the conduit is minimal because of heat transfer through radiation from the reservoir to the fluids which further maintains nanofluid at a temperature infinitesimally close to reservoir temperature.
The authors advice that compatibility tests should be run with the nanoparticle of choice to ensure that crude composition is not changed.
The Impact of Loop/Time Pick Uncertainty in Reservoir Development
Authors: Oghomienor Efe , Osuagwu Inaingo , Ozoemene Uchechukwu , Esho Muyiwa 
Published: July 2016

Abstract
One of the key uncertainties associated with a subsurface study is structural uncertainty, especially as it relates to resource volume estimation and reservoir connectivity across a structure of interest. Connectivity and volumetrics therefore play a key role in determining the viability of projects as they have impact on hydrocarbon recovery, well count and project economics. Hence, a robust and realistic understanding of the structural configuration of an area of interest in a subsurface study cannot be over emphasised. Seismic interpretation is done to define the structural configuration of an area of interest and a key stage in the seismic interpretation process is the loop picking stage. Loop picking can be particularly challenging when there is minimal well control, poor seismic data or a plague of bifurcating loops (doublets) around the area of interest.
The Zed_X1 reservoir (the subject of this paper) is a gas reservoir located in a Partially-Appraised Field (PAF) in the Niger-Delta region of Nigeria. As is typical of PAFs, the Zed_X1 field has limited subsurface data (only two well penetrations in the hydrocarbon accumulation) hence high structural uncertainty away from well control. One of the critical aspects of structural uncertainties in this reservoir is the depth of the saddle which occurs in the middle of the reservoir. On seismic, the area around the saddle occurs as doublets. Any of these doublets will translate into different reservoir volumetrics and thus development scenarios as the structure is generally flat. That is, picking the shallower bifurcating loop will generate a single culmination that can be drained by one drainage point, while picking the deeper one will translate into a deeper saddle that splits the culmination into two unconnected accumulations, hence requiring two drainage points to maximise development. The shallower arm of the doublet and deeper arm of the doublet loop interpretations were carried out and validated by wells that penetrated the structure, particularly the two wells that logged the same Gas Water Contact (GWC) on either side of the saddle.
This paper documents the potential impact that Loop Picking uncertainty can have on reservoir development decisions. The full range of resource volumes and connectivity is presented by generating different scenarios in the saddle area. The impact of this on the development of the field and on project economics is also highlighted.
Development of Recovery Factor Model For Water Drive and Depletion Drive Reservoirs in The Niger Delta
Authors: Onolemhemhen R. U. , Isehunwa S. O. , Salufu S. O. 
Published: July 2016

Abstract
Recovery factor of an oil reservoir is paramount for accurate reserves estimation and field development planning. It is usually estimated using expensive simulation or experimental studies. However, most published models account for only primary recovery. This study is therefore designed to develop a correlation model that can estimate recovery factor under both primary and secondary recovery from oil reservoirs in the Niger Delta having water and depletion drive mechanisms.
For this study, the models for recovery factor were established using statistical correlation of data collected from 136 oil reservoirs in the Niger Delta. A sensitivity analysis was performed on different parameters affecting recovery factor of water and depletion drive reservoirs. The results obtained were compared to other published models.
The results show that for both water and solution gas drive reservoirs; oil viscosity and residual oil saturation do have a strong correlation with recovery factor, while pressure, API gravity and gas oil ratio do have a strong correlation with recovery factor only in solution gas drive reservoirs. Results also show that no statistical correlation exists between formation volume factor, reservoir thickness, porosity, permeability, initial water saturation, temperature, water viscosity and recovery factor. The novelty of the recovery factor models is its ability to estimate secondary recovery factor for oil reservoirs that have been subjected to water injection.
However, the models developed in this study should be valid also to oil reservoirs in other regions having similar geological characteristics.
Analysis of ASP Flooding in a Shallow Oil Reservoir in the Niger Delta
Authors: Hillary Attah , Taiwo Oluwaseun Ayodele , Mamudu Abbas , Olafuyi Olalekan 
Published: July 2016

Abstract
ASP flooding has been most pertinent among the chemical IOR techniques because it has proven most promising depending on the candidate reservoir.
This paper presents the studies of the applicability of ASP flooding in depleted reservoirs in the Niger Delta and reservoirs of similar geologic formation for reasonable incremental oil recovery. The rate of recovery of oil from the reservoir using four different core samples (A, B, T and R) as well as the displacement efficiencies of all four core samples were comparatively analyzed. The fluid flow mechanism of ASP flooding to economically mobilize the residual oil through analyzing production performance was studied. Oil of API gravity of 42.86 degrees and viscosity of 2.5cp and core samples from a Niger delta field were used. 1% wt of NaOH, 0.15% wt of Shell Enordet 0242 and 0.02% wt of Hengfloc 63020 were the alkali, surfactant and polymer used respectively. A sequence of experimental procedure of brine saturation, oil saturation, water flooding and ASP flooding was carried out on the core samples. High pressure core holder, pressure transducer + digital display, digital camera and confining pressure pump were among the instruments used to accomplish the studies.
The results show potential to recover significant additional oil by ASP flood after the 10% recovery factor common to a large number of conventional oil reservoirs in the Niger Delta to date. The reservoir rock shows favourable response to the ASP flooding mechanism, recovering a reasonable percentage of the OOIP which is definitely handy for resolving the declining marginal fields in the Niger delta.