bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Cementing Efficiency by Optimizing the Spacer Train: Case Histories
Authors: Adesanya Olukayode , Mofunlewi Samuel S. , Ighodaro Osaze , Idongesit Victor 
Published: July 2016

Abstract
After a time-consuming cement squeeze to improve zonal isolation in a southern Nigeria well, engineers returned to the laboratory for a means to ensure primary cementing performance without costly remedial operations. Spacers have proven to be indispensable in achieving effective zonal isolation and annular slurry placement in primary and remedial cementing operations. Therefore, the engineering target was an optimized spacer train that could more effectively clean the wellbore and prevent contamination of cement slurries during displacement of wellbore fluids. Laboratory testing led to a new spacer design that has effectively eliminated the need for remedial cementing in the area.
The cement bond log for the well that required a cement squeeze showed good zonal isolation in some areas but poor bond in others, which indicated the conventional spacer train, was inadequately cleaning the wellbore. Laboratory testing confirmed that the conventional spacer system would remove some of the client's preferred drilling mud; however, a new water-based microemulsion spacer system removed substantially more mud based on tests conducted in the lab. As a result, the new high-performance, water-based microemulsion spacer was used in subsequent wells and has consistently resulted in good cement bond logs without remedial operations.
This paper describes the engineering design, application, and operational success of this high-performance, water-based micro-emulsion spacer system that has replaced a conventional spacer in an operator field in the southern region of Nigeria, West Africa. With detailed case histories of wells treated using conventional and new spacer systems, the paper highlights engineering challenges, laboratory testing, operational procedures for field deployment, and cement bond analyses carried out after slurry placement, demonstrating the spacer system to be consistently reliable in ensuring efficient wellbore cleaning and zonal isolation.
The case history wells were the first in Africa to benefit from the new spacer, which has effectively eliminated expensive and time-consuming remedial cementing operations in the area.
Cost Effective Management of the Impact of Low Quality Barite on Functionality of MWD Tools in Deep Wells
Authors: Awe S. O. , Usim M. , Akinfolarin A. , Erinle A. , Ibrahim T. , Roes V. 
Published: July 2016

Abstract
Data from Measurement While Drilling (MWD) tools are critical to successful drilling operations, because they aid real time assessment of down-hole conditions and support critical decision-making. De-risking lithology and pore pressure uncertainties while drilling exploration wells are reliant on these measurements. The reliability of MWD tools is known to be affected by mud properties, such as concentration of low- and high-gravity solids, mud viscosity and gel strength. The high mud density required for deep well drilling operations requires an unavoidable increase in solids content, which can lead to tool failure if the fluid design or quality of constituents is suboptimal.
The upper part of the 8 ½" section of the BGG-S1 HPHT well was drilled with mud weight of 16 lb/gal. The mud weight was increased to 16.3 lb/gal because of the higher pore pressure prognosis across the deeper reservoirs. The increase in mud weight resulted into higher solids content as a result of addition of more weighting agent to the fluid. After the mud weight was increased, multiple BHA runs were made because the power module of the MWD tool was not responsive. Further investigation of the repeated failures identified the root cause as solids drop-out when flowing mud through the MWD tool. The poor quality of locally sourced barite used in the operation contributed to the poor performance of drilling fluid, because it resulted in higher solids content in the mud.
The solids deposition challenge was resolved by conditioning the mud to an emulsification specification that is higher than conventional industry practice. The well was eventually drilled successfully to TD after the treatment, using a single BHA run with continuous MWD data acquisition and transmission. This paper reports the impact on the mud system associated with the quality of barite, the failure mode of the MWD power module, and the treatment of the mud to ensure technical success of the drilling operations on BGG-S1.
HSE Challenges and Management Strategies in Offshore Brown Field Development: The Experience of Ofon Field Operated by Total E&P Nigeria
Authors: Ijenyo Jude , Alum Moses 
Published: July 2016

Abstract
The Ofon field operated by Total E&P Nigeria was developed over 16 years ago and has since been producing Oil & Gas. With the identification of additional field potential, an upgrade of the facilities was conceptualized to increase hydrocarbon production and most importantly to produce the enormous gas reserve for LNG export with the stoppage of associated gas flaring, this became the Ofon2 Project. The upgrade had to be done while minimizing losses to production, which meant that the major activities (Construction and Production) on site were going to be done in parallel in what is known as Simultaneous Operations (SIMOPS).
The objective of this paper is to share the experience of the field in the management of various aspects and implementation of systems to effectively embark on the brown field development project with the attendant risk associated with simultaneous operations.
The field upgrade project brought along several constraints such as optimizing production, limitation on activities offshore as a result of space constraints, multiple contractors carrying out co-activities etc. The paper also elaborates the various challenges arising from an Offshore Brownfield field development such as astronomical increase in the number of Personnel on site, especially those employed by the different contractors, cross cultural aspects such as working with people from different parts of the world with different attitude, behaviours, performance, languages, different HSE management systems and objectives and finally, the integration of the new and existing facilities.
Several initiatives were taken to overcome the impact of the various aspects encountered during the project. These include but not limited to Personnel & contractor management, effective work organization, HSE management systems coordination, etc.
We shall conclude by highlighting the main HSE performance, the lessons learnt and keys to success for the integration, hook-up, and commissioning and start-up activities of the Project. The HSE strategies and its successful implementation demonstrate that Brownfield developments can be achieved with minimal impact on HSE performance.
Resource Volume Estimation; Dynamically Guided Volumetric Evaluation Using Streamlines
Authors: Olumide Ayeni , Adeyemi Olagunju , Ijeoma Odizuru-Abangwu , Iyegoe Igali 
Published: July 2016

Abstract
Resource estimation is a basic statutory requirement and expectation in reservoir management. Proper resource estimation allows for robust field development planning in addition to the fact that the field resources should be correctly captured at all times in the books for audit purposes. The methods for resource estimation include the following: Volumetrics, Simulation, Material Balance modelling and Decline Curve Analysis. The method applied usually depends on several factors including the reservoir complexity and production history (brown or green reservoir).
The DAZ field under review has structurally complex reservoirs with closely spaced producing wells and advanced production history. Several projects with different levels of maturation are planned for this field. These projects include work overs, implementation of field-wide gaslift and recompletions. For the completions with matured performance data, the use of Decline Curve Analysis and Material Balance fractional flow techniques for resource estimation were adequate. However, volumetrics and simulation model are the preferred techniques for the new completions and conduits with immature production performance history.
The low case simulation model methodology proved inadequate as it was difficult to obtain a good well-level history match of the production data due to the structural complexity of the reservoirs, whilst still fulfilling the requirements of hydrocarbon limits both vertically and laterally.
The conventional volumetrics method also was inadequate due to the proximal well spacing, dense faulting and the resultant complex flow patterns. The implication of this is that the drainage pattern becomes difficult to delineate and a conserved drainage area is purely theoretical.
A hybrid method which integrates the results from a well history-matched base case simulation model with the ideals of a volumetrics evaluation (drainage area and RF from analogue reservoirs) for low case resource determination is hereby presented. Essentially, the streamlines which is indicative of flow path at the end of history match from the simulation model provides guidance on the drainage pattern and area. This guide is thereafter applied in a volumetric sense to estimate the resource that can be produced by the conduit.
This alternate method incorporates all the static properties and elements of the dynamic simulation model in a qualitative sense, via the use of streamlines to guide the drainage pattern and area. It also provides for consistency in the estimation of low case and base case volumes. The result of this hybrid evaluation method realistically estimate both the in-place and recoverable volume. This volume estimation met statutory requirement of realistically reporting recoverable volume. The estimated volume was also used for reservoir management purposes.
Optimizing CO2 and H2S Removal from Natural Gas Using DEA and Alkanolamine Mixtures
Authors: Umeh Ubaka 
Published: July 2016

Abstract
Natural gas consists primarily of methane as the major constituent but also contains considerable amount of light and heavy hydrocarbons such as ethane, propane, butane and non-hydrocarbon components such acid gases (CO2 and H2S), nitrogen, water and other impurities. These acid gases must be removed to meet standard pipeline quality specifications and avoid equipment corrosion. The use of amine solvents is one of the processes used to remove acid gases from natural gas.
The aim of this report is to optimize the removal of acid gases from natural gas using DEA and alkanolamine mixtures to meet standard pipeline and LNG product specifications of 2% by vol and less than 50 ppm respectively for CO2 and less than 4ppm for H2S. The study was carried out utilizing HYSYS 8.4 process simulator to predict the operational condition of a sensitized acid gas removal unit. It entailed changing the lean amine flow rate entering the contactor while keeping other parameters constant. The lean amine temperature at various flow rates were also varied while keeping other parameters constant. Also, the effect of declining pressure on the sweetening process was also performed using HYSYS.
The graphical representations for these parameters were plotted to determine the effects of the flow rate and temperature. It was observed that at high temperatures, the surface tension increased, thereby increasing the tendency of the column to foam. Also, an increase in flow rate increased the surface tension, increased the methane content and decreased the CO2 content in the sweet gas to meet pipeline and LNG specifications.
Comparative Analyses of an Optimized Dual Expansion, Natural Gas Liquefaction Process
Authors: Okafor Emeka , Ojo Stephen 
Published: July 2016

Abstract
Natural gas (NG) from stranded regions, where they are produced is normally transported to far away regions where they are marketed and consumed. One key natural gas transportation route is based on liquefied natural gas (LNG) technology, where the natural gas is first turned into a liquid (through a liquefaction process) and then transported using large ocean-going vessels. In this paper, we present comparative results obtained from optimizing a natural gas liquefaction process. The analyses are in three steps: In the first step, we modelled a CO2-N2 single expander liquefaction process based on data published in the prestigious Journal of Natural Gas Sciences and Engineering. In the second step, the CO2-N2 single expander process is optimized by upgrading to a CO2-N2 dual expander process and results demonstrate that the CO2-N2 dual expander process consumed less power relative to a CO2-N2 single expander process, albeit with relatively high specific power values. A further optimization effort involving the substitution of the CO2 precooling fluid with a nitrogen precooling fluid revealed that the N2-N2 dual expander process provides a relatively more optimal solution when compared to the CO2-N2 dual expander process, in terms of heat duty, log-mean temperature difference, natural gas mass flow rate, production capacity and specific power. However, the N2-N2 process has a relatively higher power consumption values which can be attributed to the relatively higher compressor power requirements during the precooling process. Most of the modelling and simulation work are based on the proprietary software – Aspen Hysys 8.6.
Subsea well intervention challenges, OML 126 Wells – A Case Study
Authors: Numbere Otokini , Nwagu Chike , Ugochukwu Okoli 
Published: July 2016

Abstract
With the recent decline in price of crude, more cost effective ways are explored to ensure that the production rates are sustained and increased. The need for cost effective subsea well intervention has been discussed and documented over the last few years. The increasing number of installed subsea wells combined with the increasing age of subsea fields continues to drive demand for more efficient subsea well intervention.
Traditionally the accessibility to subsea wells is considered more difficult and represents a large cost compared to wells with direct platform access. Even minor jobs represent large expenses, leaving a gap between intervention frequency on subsea wells and wells with direct platform access. The average recovery rate for a subsea well is considerably lower than that of a comparable surface well due to the relatively more complicated well intervention and maintenance issues. Using heavy and traditional rigs for subsea intervention is costly and time consuming due to the high day-rates and mobilization aspects. The base costs are therefore considerable higher as compared to surface well intervention where tools can be deployed directly through the risers from the production unit.
At Addax Petroleum, Nigeria, the re-entry and intervention of existing poor producing subsea wells was identified as a cost effective method to maintaining production in the reasonably high cost oil subsea environment. However the major challenge with subsea intervention is the uncertainty that surrounds the planning and operations which grows exponentially with the age of the well. As factors like corrosion, and well integrity (cement and casing) all become critical in the successful delivery of the well. The availability of required service equipment and modes of operation also become very critical especially for old and obsolete Subsea equipment. There is always a significant extra cost spent if any of the identified or unidentified risks manifest.
In 2014 Addax Petroleum embarked on a successful re-entry campaign as part of the second phase of its Okwori Field Development Plan. This paper highlights on the lessons learned from the campaign, discussing the challenges, planning, and execution phases of the successful well re-entry campaign in deep water operations.
The Use of Risk Analysis and Probabilistic Methods for More Accurate Time and Cost Estimates in Subsea Intervention Operations
Authors: Ugochukwu Okoli 
Published: July 2016

Abstract
The time spent on drilling operations in the development of a field is a major percentage of the costs involved in the production of hydrocarbons. However, one of the major challenges facing drilling and re-entry operations today is the prevention of costs and schedule overruns. This is because of the nature of drilling and re-entry operations, the risks involved with the different tasks from well conception up to the completion is not properly accounted for. Other factors like the failure of a new technology planned to be deployed, the pressure of time and the increasing regulatory of safety and environment requirements have made it difficult achieving the financial and timing targets set. The shortfalls in well cost estimation and control are due to reliance on outdated or poor methodologies.
Generally, drilling AFE's (Authorization for Expenditure) are generated by applying deterministic methods to offset data and, which primarily consists of the recorded and documented experience of the drilling operations. From the analysis of these data, estimates for drilling performance and the likelihood of facing drilling complications are estimated. Added to all these are also an element of expert judgment, though subjective, that is drawn upon in the estimation of time and costs for the new well/s to be drilled or re-entered.
These estimates suffer from the lack of a true scientific approach to predict time and costs which becomes apparent immediately there is a deviation from the planned operations.
There has been limited published work involving the applications of probabilistic methods in drilling engineering, particularly when estimating times and costs for re-entry and drilling operations. This fact is even more acute when considering the evaluation of re-entry opportunities and new drilling technologies. There is little or no scope to incorporate an estimation of risks and non-productive time (NPT) in a meaningful manner.
This paper presents an accurate probabilistic and risk analysis approach using a subsea re-entry well as a case study. An intervention operation was planned and this method was used to accurately predict the amount of days (and cost) required for the operation, factoring in all the possible risks and time impact on the operation. A deviation of less than 5% was observed when the actual expended time and cost was compared to the planned.
Evaluation of the Methodologies of Analyzing Production and Pressure Data of Tight Gas Reservoir
Authors: Fekete Paul , Ekpedekumo Richard , Dosunmu Adewale , Odagme Samuel , Bovwe Ediri 
Published: July 2016

ABSTRACT
Since production curtailment for other than engineering reasons is progressively vanishing, and more and more wells are currently producing at capacity and showing declining production rates, it was viewed as auspicious to display a brief audit of the advancement of decrease bend investigation amid the previous three or four decades. A few of the plebeian sorts of decline curves were talked about in detail and the mathematical relationships between cumulative production, time, and production rate and decline percentage for each case were contemplated.
This work summarizes the different production analysis methods published in the literature and evaluate the most applicable methods for use in determining well and reservoir parameters, and estimating the gas in place for tight gas reservoirs. Field and simulated examples are presented to illustrate the evaluation of these methods. Results from this study show that modern methods such as Blasingame, Agarwal and Gardner, Normalized Pressure Integral and the Flowing Material Balance are valuable tools for production history and pressure data to determine reservoir parameters and reserve for tight gas reservoirs.
An Improved Model for Estimating Productivity of Horizontal Drain Hole
Authors: Adesina Fadairo , Paul Anawe , Oyinkepreye Orodu , Adebowale Oladepo 
Published: July 2016

Abstract
Horizontal wells have become a popular alternative for the development of hydrocarbon fields around the world because of their high flow efficiency caused by a larger contact area made with the reservoir. Most of the analytical model existing in the literature on horizontal productivity either assumed that the well is infinitely conductive or the flow is uniform along the entire well length. Guo et al (2007) formulation is one the most recent and accurate models reported in the literatures for predicting production rate in horizontal well considering the frictional pressure drop along long horizontal drain hole. In this paper, an improved predictive model that takes into account the effect of other possible wellbore pressure losses on production rate variation of long horizontal well was developed. Results show that the discrepancies in the predictions of the previous models and field results were not only due to effect of friction pressure losses as opined by previous authors but may also be due to loss due to fluid accumulation experienced by the flowing fluid in a conduit. The effect is most pronounced at the early production time where initial transience at the onset of flow is experienced. The improved model was applied to the same field case study used by Guo et al and results is much more accurate and show that the error of the new model is less than 4% compared to 20% reported by Guo et al. This work provides reservoir engineers an accurate and handy tool for prediction and evaluation of horizontal wells.
An Evaluation of Underground Storage as a Potential Solution for Stranded Associated Gas in Oil Fields
Authors: Lawal Kazeem A. , Ovuru Mathilda I. , Eyitayo Stella I. , Matemilola Saka , Adeniyi Ayodeji T. 
Published: July 2016

Abstract
In the absence of a gas market, the management of the gas associated with oil production often poses serious challenges to the development of oil fields, resulting in potentially stranded gas resources. While gas flaring was the default solution, more stringent carbon constraints have rendered this solution unattractive, owing to its negative health, safety, environmental and socio-economic impacts. One potential solution entails injecting the otherwise stranded associated gas (AG) into underground geologic systems for temporary storage, but re-producing same when a viable gas market becomes available.
Faced with the challenge of providing temporary AG solution for a new oil development in the shallow offshore area of the Niger Delta, this paper presents an overview of candidate solutions, which include (i) venting, (ii) flaring, (iii) injection for improved oil recovery, (iv) underground sequestration (AG injected but not re-produced), and (v) on-site conversion to natural-gas hydrates to facilitate evacuation to other outlets. Their relative strengths and weaknesses are examined relative to this case study.
The paper details the key aspects of a reservoir-engineering assessment of temporary AG storage in a non-associated gas (NAG) reservoir for later monetisation of both the native NAG and alien (injected) AG resources. Rigorous numerical-simulation studies highlight the key factors that control both the injection and production phases of the subject reservoir. For a given set of abandonment conditions, effects of the gas volume injected prior to the production phase on the ultimate recovery factors of the native and alien gas resources are presented. Additionally, the relative advantages of matrix, pseudo-fractured, and fractured injection modes are explored.
Compared against the above-mentioned alternative solutions in terms of (i) effective sales volume of hydrocarbon, (ii) infrastructural requirements, and (iii) net carbon savings, underground storage is the most attractive solution to address stranded AG in this example field, and possibly others.