bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Whipstock Sidetrack Operations
Authors: Ugochukwu Okoli , Okubor Eleanor , Aigbedion Prince , Ayodele Adetokunbo 
Published: July 2016

Abstract
The recent decline in the price of crude oil has necessitated more cost effective ways to sustain and increase production worldwide. From July 2014 to May 2015, Addax Petroleum Development Nigeria Limited (APDNL) embarked on a successful re-entry campaign in its shallow and deep water fields.
These wells' Vertical Lift Performance (VLP) had been compromised by excessive sand production; rather than drilling new wells to recover the trapped reserves that would otherwise not have been produced by the impaired wells, it was more optimal to re-enter the existing wells, recover their completions accessories and then side track into optimal locations within the reservoirs of interest.
These suboptimal wells were not considered for recompletion because in addition to excessive sand production, increased water cut and Gas Oil Ratio (GOR) meant that the drains were no longer in the best positions within the reservoirs to produce the trapped oil estimated to be left in the reservoir. The new side track wells would have their drains placed higher in the reservoir (based on production data from the soon-to-be-abandoned wells), but would not bear the full costs of drilling new wells nor their associated future abandonment liabilities.
Seven wells were re-entered during this period and side-tracked in cased hole with the use of hydraulic whipstocks, none of the side tracking operations witnessed significant down time. The whipstock was deployed to its intended setting depth, casing window milled and additional rat hole drilled in one trip.
Each phase in the whipstock operation had inherent risks and challenges that were successfully managed by identifying these risks early in the planning phase and mitigation steps put in place to ensure the operations were carried out with minimum Non Productive Time (NPT) as the cost implication of an operational mishap would have been severe.
This paper reviews the re-entry operations performed, challenges encountered with deploying hydraulic whipstocks. It also identifies the Key Performance Indicators (KPI) used to benchmark and compare the operational performance. Finally, this paper highlights the lessons learned during the re-entry campaigns and measures put in place to optimize future operations with respect to deploying whipstocks.
Cost Reduction Initiatives in a Low Oil Price Regime and Beyond: SEPLAT's Experience
Authors: Iyua Donald , Okongwu Obinna , Vaughan Bolutife , Orimoloye Samuel 
Published: July 2016

Abstract
Since the global crude oil price slump began in June 2014 ($125.86 per barrel: last known price peak before slump), companies in the oil and gas business have witnessed a sharp decline in revenues and eroded profits. Many international oil companies have declared huge losses running into billions of Dollars for 2015. There are efforts at reducing operating costs with attendant job cuts and freezing of non-essential projects. Global investments in projects in oil and gas have declined to levels seen only in the 1980s. With oil prices hovering at $40 per bbl, many projects become unviable except a lot is done to lower the unit development costs. This is more so for brown field developments where the reservoirs are matured. This paper will present the efforts made at SEPLAT to lower operating cost especially through reduced well delivery costs. The paper will mention some ideas explored in other areas such as contracting & procurement and business processes.
Seplat Petroleum Development Company PLC, an independent operator in Nigeria's upstream business has put in place sustainable measures that has helped to ensure she remains profitable while the low oil price regime lasts and beyond. The Drilling and Completion department which accounts for over 55% of the annual expenditure was at the forefront of this endeavour. Engagements were held with all contractors mainly aimed at mutually agreed reductions in contract rates. Discounts were obtained ranging from 5 – 30 % across various vendors and services. A review of well delivery processes, long lead items and logistics, appropriate technology and improved planning has led to some improvements. The competitive re-tendering of most services and the maturation of cost saving technologies will further improve wells project delivery cost and time, going forward. Company wide cost reduction initiatives and business process improvements will ensure the long term profitability of the company.
Revisiting the Assumption of Local Thermal Equilibrium in Thermal Floods
Authors: Lawal Kazeem A. 
Published: July 2016

Abstract
Notwithstanding their complexity, a good understanding of the heat-transport mechanisms and the associated temperature distributions is a critical success factor for the design and management of thermal projects exploiting underground oil resources. However, for mathematical convenience, it is often assumed that the reservoir exists in a state of local thermal equilibrium (LTE), which implies that the trio of injected heating fluid, in-situ fluid and the rock matrix in a particular location always exist at the same temperature. In essence, current treatments assume that the in-situ fluid and rock matrix reach the temperature of the injected fluid immediately they are contacted by the latter, tacitly neglecting possible time lag to accomplish heat exchange among these three elements.
Applying the principles of energy conservation at a pore scale to each element of the trio, this paper develops and solves a one-dimensional heat-transport model to investigate the validity of this fundamental assumption in thermal floods. The approximate analytic solutions under isothermal boundary conditions are presented in both Laplace and time domains. Employing the resulting solutions and a set of realistic input data, the conditions and time scales of validity of the LTE assumption are probed for steam, which is a popular and efficient heating fluid for oil reservoirs.
Results of the sensitivity studies suggest that the assumption of LTE remains credible for most realistic thermal floods. These findings notwithstanding, some conditions that threaten the validity of this fundamental assumption are highlighted.
Some Lessons from Gas Condensate Reservoir Development Evaluation Using Experimental Design
Authors: Shittu Hammed , Enekhai Henry , Ambastha Anil 
Published: July 2016

Abstract
Experimental design method is very useful in green field development. It helps to understand the impact of uncertainties on ultimate recovery, and hence, gives guidance on business decision making. Outputs from the process (Pareto/Tornado charts, selected models) are good exhibits for use in the uncertainty management plan, which also drives data acquisition and work plans for future stages/phases of the project.
This work shares some lessons from using experimental design for development planning of two Non-Associated Gas (NAG) condensate reservoirs. It demonstrates the importance of selecting appropriate design for proxy generation/Monte Carlo simulation runs – and eventual model selection.
This paper has two case studies: (i) a gas condensate Reservoir "A," with total of 20 parameters (9 discrete and 11 continuous variables), and (ii) another gas condensate Reservoir "B", which has 22 parameters.
Folded Plackett-Burman (FPB) design was first used in both cases. However, owing to limited number of runs, only linear proxies could be created. This did not meet the objective of the process, because it does not allow for generating interaction terms among parameters. The FPB runs were therefore used only as screening studies, while 3-level D-Optimal designs were subsequently used for response surface model (proxy) generation.
Four sensitivities were done on Reservoir "A": (i) 20 parameters with 300 D-Optimal runs; (ii) 14 parameters with 300 D-Optimal runs (after screening out less impacting parameters on objective functions); (iii) 20 parameters with 500 D-Optimal runs; and (iv) sensitivity (i), but with additional fresh 200 D-Optimal runs. The two sensitivities done on Reservoir "B" are: (i) 22 parameters with 200 runs; and (ii) 15 parameters with 300 runs. It was observed that only sensitivities (ii) and (iii) for Reservoir "A", and sensitivity (ii) for Reservoir "B" yielded meaningful proxies.
In conclusion, using Folded Plackett-Burman (FPB) designs alone in cases with many variables, as shown in this work, may not lead to meaningful proxies (especially, when there are interactions among parameters) because it is restricted to only linear proxies. Also, it is important to have adequate number of 3-level design (D-Optimal) runs for both process efficiency and proxy generation. Too few runs result in unreliable proxies, whereas too many runs take more time/computing resources. In addition, carrying large number of variables into the 3-level design stage requires more runs and also leads to more cumbersome proxies.
Gas Field Development Planning: Issues and Practical Solutions
Authors: Ambastha Anil K. 
Published: July 2016

Abstract
Nigeria has vast amount of gas and gas-condensate resources that have not been developed because of country’s traditional focus on oil reservoirs in the past. However, country is now embarking on a systematic development of gas resources. Objective of this study is to discuss issues being faced by all parties to evaluate gas resources and practical solutions to move forward with gas development on a large scale.
This paper discusses commercial (including team dynamics), technical, data analysis, and organizational capability issues relevant to development planning for gas fields. Practical solutions such as open and full communication among all stakeholders, due diligence to locate and analyze technical data, and proper bench-marking and testing of relevant recovery mechanisms in commercial software packages are proposed that would lead to proper evaluation of gas resources. It is emphasized that work alignment to resolve uncertainties and reach appropriate decisions is absolutely critical for project success. While practical solutions presented in this paper are especially geared toward gas field development, many of these thoughts and concepts are applicable for technical analysis of all petroleum engineering projects.
Alkaline-Surfactant Flooding in Niger-Delta: An Experimental Approach
Authors: Onyekonwu M. , Akaranta O. 
Published: July 2016

Abstract
Oil and gas production in Nigeria, recently advanced into secondary method of recovery of hydrocarbon aiming at tertiary recovery methods known as Enhanced Oil Recovery. It is of great importance to start the preparation for this phase now. Alkaline-Surfactant flooding is a tertiary recovery method used to produce extra oil from mature fields where oil is trapped due to capillary forces. These alkali are added to mostly reactive crude; they react with the naphthenic acid in the crude oil which forms a crude soap through the process of saponification, but most times, this crude soap are not sufficient, so surfactant are further injected to optimize its concentration in order to effectively reduce the interfacial tension between oil and formation water. Three conventional alkalis (NaOH, Na2CO3 and KOH) and two synthetic surfactant (Xero Detergent and Sodium Dodecyl Sulphate) were used as Enhanced Oil Recovery agent for a sand pack flood test in the laboratory. The comparative result showed that the Na2CO3 at 1%w/v concentration was better, though the KOH at 2%w/v concentration gave the best result marginally. It was also observed that the XD at 0.1%w/v concentration gave a result that can be compared to that of 1%v/v concentration SDS. Which shows that XD can be used as a substitute for SDS with low cost and availability been added advantage. Additional oil recovery after waterflooding for NaOH, Na2CO3, KOH, XD and SDS are 13.3%, 18.2%, 17.5%, 11.5% and 15.2% respectively.
Getting the Most of Niger Delta Fields; Countering the Effect of Urbanisation: SPDC Case Study
Authors: Sukubo Ibianga , Nwabueze Vincent , Okoro Chidi , Dennar Linda 
Published: July 2016

Abstract
Urbanisation effects around fields in the Niger Delta has made onshore hydrocarbon production activities not to thrive in a clime of increasingly health, safety and environment (HSE) oriented operations leaving most well locations encroached by emerging towns, with flowline right-of-way (RoW) already encumbered.
Sigma field is one of SPDC fields in the Niger Delta that were impacted by third-party encroachment. An initial assessment showed 26 producing oil conduits and 11 RoWs were impacted resulting into production deferment of ca. 10,300 bopd. Given an encroachment resolution cost of ca. US$37mln budgetary provision there was the need to carry out cost-benefit analysis of the additional investment.
This paper presents the approach adopted to get the most out of the field in the Niger Delta whilst countering the effects of third-party encroachment through set criteria: well cluster based on common location, and creaming based on recoverable volume, conduit level reserves and conduit potentials. 19 conduits were recommended for re-opening with a life cycle recoverable volume of 33MMBOE saving US$9.6mln. It was concluded from preliminary economics that the encroachment resolution cost of US$37mln can be accommodated by the additional oil and gas production notwithstanding the rigour required for handling third-party issues.
An Integrated Approach to Reservoir Quality Prediction of Untapped Oligocene Reservoir Offshore Western Niger Delta
Authors: Obinna Chudi , Anaevune Austin , Lewis Helen , Stow Dorrik 
Published: July 2016

Abstract
A belief that has been widely accepted amongst petroleum engineers and geoscientists in the oil industry is that early hydrocarbon emplacement in sandstone reservoirs is capable of inhibiting quartz cementation, thereby leading to porosity preservation. Results from this study of the timing and degree of cementation of a deep Oligocene potential clastic reservoir are used to predict: (1) the onset and volume of quartz cementation in the potential reservoir, and (2) the effect of early hydrocarbon emplacement on reservoir quality. In this study, burial and thermal history of untapped deeper Oligocene plays that lie below the highly productive clastic Miocene plays of the western deep Offshore Niger Delta are investigated using basin modelling enhanced by quartz cementation modelling. Of particular interest is the timing of charge to the reservoirs and the timing of diagenesis. Quartz cementation was modelled using the Walderhaug quartz cementation algorithm as a precipitation rate limiting reaction controlled by the rock fabric and temperature. Model calibration was primarily achived using physical properties measured from well A1- the only well that penetrated the top of the Oligocene sequence.
Simulation results indicate that less than 0.5% of pore space of the shallow proven hydrocarbon-bearing Miocene sands have been cemented, having been exposed only to low temperatures unfavourable for quartz precipitation. This is in agreement with measured porosity values exceedin 30% and permeability in the Darcy range. The deeper Oligocene succession has been buried to depths where temperatures are simulated to exceed 70° C favouring quartz cementation. The cementation model of the Oligocene sediments indicates that less than 14% of the total porosity has been occluded by quartz cement. However, the charge model simulates peak hydrocarbon saturation being reached when less than 7% of the pore space, in all four simulated accumulations, was quartz cemented. Hence the rate of quartz cementation is likely to have reduced from the time of peak oil charge onwards, thereby preserving a significant fraction of the porosity in the potential Oligocene reservoirs.
The integration of all techniques adopted in this study that results in a holistic outcome is believed to represent a novel approach in reservoir quality prediction. If the Oligocene is proven then it would represent a significant new play that is likely to extend beyond the study area across the western offshore Niger Delta.
Technical Evaluations for Reservoir Disposal of Gas-to-Liquid GTL Plant Effluent Water
Authors: Nwume Michael , Oluseye Ekun , Oyinda Onigbogi 
Published: July 2016

Abstract
In compliance with local regulation in Nigeria on open water discharge and environmental stewardship considerations, aqueous Gas-to-liquid (GTL) plant effluents usually treated to meet specification for discharge to the Escravos River were characterized for consistency in quality for disposal by injection into oil/gas reservoirs.
Gas-to-Liquid plant operated by Chevron in the Escravos area has considered the discharge of their aqueous effluent water through the Escravos Produced Water system as an alternative to river dump. These effluents are different in composition and quality with produced water from Oil/Gas reservoirs due to the various sources producing the effluent. To qualify for reservoir disposal, a detailed characterization of the GTL effluent was performed to determine acceptable potential impact on the surface and subsurface facilities.
This paper therefore provides the necessary technical evaluations required for effective reservoir disposal of GTL effluent water when considered to supplement the injection volume or serve as alternative injection water to the conventional produced water re-injection.
A Systematic Approach to E-Inflow Control for Horizontal Well Production Optimization in Shale Oil Reservoir
Authors: Makinde Favour A. 
Published: July 2016

Abstract
Shale oil reservoirs are characterized by low porosity and very low to extremely lowpermeability which makes the oil content difficult to produce at economic rates without being enhanced. The current production optimization technique in the oil industry uses a combination of horizontal well and fracking. However, there is a possibility of linearly increasing inflow with high liquid loading at the horizontal well heel which can seriously choke offtake of the fluid.
This paper, therefore presents a holistic approach based on wellbore hydraulic optimization and systematic inflow control to maximize deliverability from shale oil reservoirs. Wellbore hydraulic optimization was achieved through rheological characterization of viscous liquid-rich shale at different nodes whilst systematic inflow control was achieved through selective inflow control into the wellbore in order to distribute fluid influx uniformly and avoid early breakthrough of unwanted fluids.
The results presented prove that using the new modelling approach offers better deliverability overall compared to the current approach known.
Hitherto, there has not been a holistic characterization of fluid rheology cum systematic inflow control, this work offers this novel approach as a contribution to the existing methods of optimizing production from shale reservoirs.
A Proxy Based Approach for the Preliminary Evaluation of New Gas Condensate Field for Development
Authors: Omeke James E. , Ezeukwu Toni , Adesun Julius , Ekesiobi Chidi 
Published: July 2016

Abstract
With increase in gas demand to meet both export and domestic gas obligations, amidst oil price volatility, it is imperative that oil and gas companies embarks on activities that will minimize investment risk and initiate robust development plans. It becomes a very big challenge at the onset of new gas condensate field development owing to limited geological and engineering data.
To ascertain the technical feasibility and economic attractiveness of a gas condensate field, a very lengthy study work is required to unravel the complex interplay of subsurface uncertainties; hence, a quick screening tool is therefore required for quick decision making and investment prioritization. A proxy of recoverable reserve for the new field was developed for this purpose using design of experiment (DOE) and response surface model (RSM). However, although DOE was initiated in the industry to reduce computation, it remains computationally expensive especially in compositional simulation were many degrees of freedom exist in the uncertainty parameters.
This study presents a new gas condensate field case study where both engineering and earth model variables were systematically varied to assess the impact of main uncertainties on forecast level of gas condensate production/reserves using RSM proxy. This approach was validated when key risks associated with new gas condensate field development were quantified.
This paper provides a technical and economic feasibility assessment tool for low risk decision. It will also assist in data acquisition program and roadmap construction especially when the most influential uncertainty parameters influencing gas and condensate recoveries are identified.
Borehole Stability Management Using the New Mudweight Window Concept; A Case Study of Well KTY 02, KTY 03 and KTY 04
Authors: Bassey Akong , Dosunmu Adewale , Otutu Friday , Usim Mike , Majekodunmi Kamaldeen 
Published: July 2016

Abstract
Borehole instability is one of the major factors that contribute significantly to additional unplanned cost in drilling operations irrespective of the wellbore inclination. Problems generally build up in time, starting with the tensile or compressive failure of the borehole wall, followed by transfer of fragments to the annulus and finally-if hole cleaning is insufficient-culminating in such difficulties as tight hole, breakouts, caving, pack off, borehole collapse and stuck pipe.
Horizontal and highly deviated wells in normal faults stress regimes present more difficult challenges than low inclined wells due to compressive or shear failure of the wellbore. Wellbore stability issues are more pronounced as the wellbore stress difference reaches at maximum with increase in inclination. Proper planning of the well trajectory and mud weights are crucial to avoid such complexity which causes huge rig downtime, NPT and cost. With the aid of in-situ stress, pore pressure and rock strength analysis the wellbore stability can be assured with suggested optimum deviation profile and mud weights window for different inclinations and azimuths.
An attempt has been made to perform the wellbore stability analysis for three high angle and three horizontal wells (with drain-extension of about 500ftahd) development wells in Niger Delta which is planned for production in near future. In our workflow, the seismic data and offset well information have been incorporated to generate pore pressure, optimum mudweight, shear failure (minimum envelope) and fracture pressure gradient. Rock physical parameters have been calculated from the offset well's logs and calibrated with laboratory tested dataset to use in the stability analysis for well KTY 02, KTY 03 and KTY 04. In the study area, wellbore stability analysis was carried out in both the pilot and drain hole sections of the horizontal wells. However, because of horizontal drilling plan in drain holes, differences in principal stresses in the wellbore and their physical implication on stability was plotted and interpreted through stress concentration plot and safe MW window analyzer extensively. The stresses and the rock strength datasets input were used to derive the collapse failure gradient curve (CFG) using the Mogi failure criteria. The wellbore circumferential and radial stress distribution analysis has been done for different depths with the inputs from stresses and the corresponding cohesive strengths and the Frictional Angles.
With these analytical results, we have recommended the wellbore trajectory along Shmin and SHmax direction and along the maximum good reservoir facies with corresponding mud weight (window) profile required to drill these wells with NPT as a result of instability consequences such as stuck pipes and jeopardizing wellbore integrity during logging, casing running and completions.