bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Polymeric Water and Gas Shut-Off Treatments in Oil Wells
Authors: Egba Amba Ndoma , Ajienka Joseph A. 
Published: July 2017

Abstract
Controlling excessive gas and water production from oil wells is still a major problem in the global E & P industry. Various strategies have been advised in the petroleum literature by industry experts and vendors. Different service companies continue to lay claim of innovative Water and Gas Shut-Off (WGSO) products that will offer better results. No doubt, there are noteworthy improvements in unwanted water and gas control technology, the problem however, has continued unabated.
Polymers have been developed to help in the reduction of the water-oil-ratio (WOR) while at the same time not limiting the flow of hydrocarbon. Polymer-foam for gas shut off also reduces the GOR, but not the oil flow rate. Though, some successes have been reported in polymer water and gas shut off in oil wells, a survey of field cases however shows, that most treatments have been unsuccessful. Our findings suggest that different diagnostic methods, treatment design and applications vary from vendor to vendor even with the same diagnostics. Companies also use different economic yardsticks to measure the success of WGSO operation. This has led to tremendous failures in polymeric WGSO application.
Relying on a data base of WGSO field cases, some treatments could guarantee substantial increase in oil production while in others the production was relatively small, zero and sometimes negative. Several factors could be responsible for these; Wrong diagnosis and poor candidate selection, improper treatment design and application. There is also lack of an economic model to evaluate the success of a polymer water and gas shut off treatment.
This paper therefore evaluates the causes of success or failure of the polymer water and gas shutoff treatment in the Niger Delta
Multirate Welltest Design - Niger Delta Field Experience
Authors: Ndukwe Reginald , Umoh Magdalene , Adepoju Yaqub 
Published: July 2017

Abstract
Multirate welltests are conducted to determine well deliverability, skin and distance to major fault boundary; as well as reservoir data like permeability and pressure. A reservoir was planned for development with four wells to supply about 500 MMscf/d of gas to a primary treatment facility.
The proposed wells were designed for multirate welltests to boost confidence on meeting the gas supply obligation. The multirate welltest program includes (1) Initial Build Up, (2) Flowing, (3) Final Build Up and (4) Static Survey periods. The test design determines optimal duration for each activity in the program; to ensure the test objectives are achieved. This paper shares results of the test designs for the wells and insights gained from the exercise.
The results show that wells close to boundary fault (less than 250 m gap) were not good candidates for final build up survey as the fault signal appears early (within 0.1 hr survey time) as boundary effect; thereby overlapping with wellbore storage effect phase and masking infinite acting radial flow period (used for estimating well and reservoir parameters). Hence, final build up was not proposed in such wells. Those parameters can be estimated from other wells in the same reservoir. Sensitivities were done by varying the reservoir structure, permeability, well skin and wellbore storage effect.
Test design results also show that infinite acting radial flow period signal was observed within 0.1 to 2 hrs of final build up; followed by fault boundary response visible from 2 to 24 hrs. It can be concluded that final build up survey period of 10 hours is optimal to meet the test objectives.
Standardized Well Design Driving Project Delivery in an Offshore Brown Field
Authors: Ademide Adegbite , Rukayya Dabana , Abisola Kuku , Ejiro Ogbodu , Aihanuwa Ukponmwan 
Published: July 2017

Abstract
In the current ‘lower for longer’ oil price environment, there is a need to ensure sustained delivery of wells at competitive costs without compromising safety and well integrity. Well operations in a brown field give unique opportunities to harness the advantages presented by knowledge of the field as well as the quantity and quality of subsurface and operational data available. One of such advantages is the opportunity for standardizing the well design for the field.
This paper describes the journey to arriving at a standardized well design in the Bonga field, the subsequent contribution to efficient delivery of projects and the challenges experienced in its application. Standardizing the well design has significantly reduced the need to ‘reinvent the wheel’ in the opportunity maturation process as detailed front end loading can then be carried out field-wise with iterations done for specific wells as required. Execution of operations on the field has witnessed continuous improvement as operations are usually batched and kept consistent across wells. With materials requirements clearly defined, significant savings are achievable through longer term contracts and effective management of the materials inventory.
The application of a standardized design is not without some associated challenges, regrets and potential blind spots. Proactive identification, evaluation and knowledge of these challenges were required to ensure that they were effectively managed. Details on how some of these challenges were managed as well as results from the application of the standardized well design philosophy in the Bonga field are provided in this paper.
Productivity Study of Sand Control Performance of a Mature Developed Reservoir in the Niger-Delta
Authors: Nwosu Obiora , Olagunju Adeyemi , Agwuncha Frank , Odumodu Somtochukwu , Oghene Nkonyeasua , Ori-Jesu Efeoghene 
Published: July 2017

Abstract
The productivity of oil wells depends on a lot factors such as and not limited to environment of deposition, reservoir thickness, permeability, reservoir drive mechanism, drain hole length and formation damage at the near well bore region. The productivity of oil wells can also be linked to the effectiveness of the sand control method deployed in the well. Sand control methods play very important roles in safeguarding our assets, maximizing production from assets and reducing life-cycle OPEX for the well.
This paper presents a comparative approach towards understanding the effect of different sand control methods on productivity of wells completed in a mature reservoir in the Niger Delta. The methodology involves the use of statistical comparison of the production performance of 4 sand control methods installed in the XYZ reservoir in the YED field. The approach considers the productivity performance, the average sand reliability index, and the intervention frequency ratio.
The productivity performance of the completed conduits on XYZ reservoir shows that conduits completed with Slotted Liners showed impressive production performance as well as low sand production, while the wells completed with IGP had better production performance when compared to other sand exclusion methods. The drainage points completed with SCON showed average production performance, with high sand production averaging around 25-30 pptb for the completed conduits. The conduits that were completed with MCUGP showed below average production performance as well as high sand production.
The results in this work will help provide an easy guide to sand control selection as it concerns productivity in the Niger-Delta region. It will also deepen the understanding of the performance of different sand control methods in the Niger-Delta Region.
Integration of Pulsed Neutron Log Data: A Cost Saving-Value Driven Approach for Justification of Well Intervention
Authors: Maxwell-Amgbaduba Sunday , Okpere Adrian , Williams Omolara 
Published: July 2017

Abstract
The ability to perform remedial activities to enhance production from existing wells in order to extend field life is an essential component of brown field management. Predicting the movement of hydrocarbon/water behind casing and estimating remaining hydrocarbon column ensures economic value on proposed activities can be quantified. Fluid contact measurements over time are useful for tracking reservoir performance, planning work over and enhanced recovery strategies, as well as diagnosing production problems such as water influx.
This paper highlights the value of integrating pulsed neutron log data with other subsurface data and models to provide a robust solution in well intervention. The case study demonstrates how pulsed neutron log data has helped resolve multiple challenges such as; Estimation of remaining hydrocarbon column and volume, perforation placement uncertainty, optimizing reservoir block development strategy and ensure robustness of reservoir dynamic models.
Results from the case study show that integrating pulsed neutron log data in a work-over intervention could amount to huge cost savings (&gt;$10,000,000 dollars in this case) in proposed operation. Additionally, calibration of acquired log data with existing dynamic models led to perforation optimization which gave resource volume increase of about 15% from two reservoirs against pre-estimated volume.
Multi-Method of Estimating Lifecycle Technical Ultimate Recovery in a Natural Depletion Gas Reservoir
Authors: Tunji Bakare , Waazor Korubo , Olugbenga Daodu , Suleiman Ahmed , Chima Emelle 
Published: July 2017

Abstract
Gas reservoir development at inception is often linked to detailed surface infrastructure development and long term contractual agreements with only a few appraisal wells. A thorough and detailed technical estimation of the size of the pie is an important step in the right direction. This is characterized by seismic acquisition and interpretation, scanty appraisal wells proving useful reservoir and fluids properties data and contact tagging. Calibration of regional properties with nearfield analogue can also be quite useful.
All these form the basis of the field/Reservoir development plan. For a gas development, the optimum development wells depend on a variety of factors identified at the field development stage often targeting the most viable crestal part of the reservoir for optimal development. Post drilling of development wells where reservoir static properties are fairly known and at the early stage of production when there is paucity of production data, it is imperative to adopt a robust approach to evaluate the technical UR.
In early producing life of the reservoir when reservoir pressure data is needed perhaps the most, long shuttin-in to take static pressures can be abit problematic due to commercial commitments. There is heavy reliance on planned and unplanned shutins to take useful pressure data used in calibrating reservoir models.
This paper takes a critical look at multiple approaches to estimating robust ultimate recoverable gas volumes with reservoir geology as an essential guide using tow distinc approaches; Detailed 3D simulation model and P/Z estimate method using Piper, McCain and Corredor z factor estimates. Lastly the range of uncertainties of the input data was used to estimate the low base and high cases.
Impact of Intra-Reservoir Faults on Fluid Connectivity and Recoverable Volumes in Reservoir Blocks That Have Shown Over Production – A Case Study of a Niger Delta Field
Authors: Orekoya A. O , Oghene N , Olagunju A , Odumodu S , Ori-jesu E , Nwosu O , Agwuncha F 
Published: July 2017

Abstract
The impact of intra-reservoir faults on fluid connectivity and recoverable volumes in any reservoir depends principally on structural uncertainties (fault extent, fault throws, fault zone, fault heave, fault sealing capacities etc.) associated with the reservoir.
This paper focuses on the integrated approaches used to determine block by block fluid connectivity, re-assignment of estimated hydrocarbon initially in-place volume and its associated recoverable volumes in different reservoir blocks in view of production performance and complex fault architecture in the field.
In this study, we have explored the feasibility of determining fluid connectivity across reservoir blocks and their associated recoverable volumes by integrating reservoir performance (post-production data) with the reservoir structural uncertainties. Over 50 wells have been drilled in the field and their penetrations spread across the reservoirs. Pressure data were acquired across most of the blocks in the reservoir.
The reservoir is sub-divided into separate blocks and it has over 25 years of production with evidence of over-production (Np &gt; Ultimate Recoveries) experienced in some of these blocks. This over-production triggered the need to integrate available data (Performance, Pressure data, Fluid Contacts, structural morphology etc.) to re-evaluate the impact of the intra reservoir faults on the estimation of the hydrocarbon in-place volume and recovery in the field.
The integrated approach has aided the re-estimation and re-assignment of the associated volumes on a block by block basis thereby promoting the opportunity for a robust infill well planning and further development of the field.
3D Static Modelling of An Offshore Field in the Niger-Delta
Authors: Duvbiama Omolara , Ikomi John 
Published: July 2017

Abstract
The complex nature of deep water sediments requires the use of a full field 3D static model to enable better understanding of the reservoir characteristics of the field. This study focuses on the 3D static modelling of the 458 reservoir in Botti field to facilitate field development.
The Botti field is a partially appraised field located about 20km offshore Nigeria. A total of four wells have been drilled in the field and only two wells encountered the target reservoir. The depositional environment is mainly deep water slope channel sands with some submarine fans.
The morphological uncertainties relating to the slope channel sands deposits, requires a detailed 3D static model which defines reservoir characteristics such as channel orientation, continuity and connectivity.
The reservoir evaluation involved the use of core-log integration to identify the facies in the reservoir, seismic interpretation as well as correlation using a sequence stratigraphic approach to understand the reservoir architecture and property distribution.
Using the information obtained from analysed data, an analogue field and literature review, a conceptual model was proposed for the reservoir which served as a precursor for a 3D static model.
To quantify the uncertainties associated with the In-place volume, a monte carlo simulation was done to obtain the P10, P50 & P90 STOIIP values.
Sensitivity analysis using a tornado chart to evaluate impact of STOIIP parameters on the hydrocarbon in-place volumes were done and it showed that N/G had the highest impact on the STOIIP.
The results of this study show that the 458 reservoir is a weakly confined channel complex system made up of the 458_1, 458_2 & 458_3 channel complexes.
A P50 STOIIP was estimated as 150MMstb. This is about 43% reduction in the initial volume calculated before the full field static model.
Thin Oil Rim Development in a Mature Field – An Okan Field Experience
Authors: Ogbuagu Frank , Afolayan Femi , Esan Femi , Obot Nsitie , Adeyemi Ganiyu , Okpani Olu 
Published: July 2017

Abstract
This paper summarizes the strategy adopted in the development of two thin oil rim reservoirs in Okan Field, Offshore Niger Delta, Nigeria.
Its objective is to elucidate the strategy, engineering analyses, subsurface assessment and production procedures set in place to optimally develop the reservoirs.
Both reservoirs have oil thickness of &lt;30 ft with gas thickness of &gt;100 ft. The adopted development strategy for the two reservoirs involves the drilling of 4 wells, 2 in each reservoir, to drain the remaining oil reserves, prior to gas development.
Because of structural and fluid contact uncertainties, soft landing was incorporated into the well designs. Shale-to-shale correlation was used for accurate horizon depth prediction and detailed simulation models with local grid refinements were employed to determine optimum well orientation, landing depth, lateral length and aquifer properties. Details on their use to maximize value are shared.
While drilling, Azithrak™, a Baker Hughes tool, was used in geosteering the lateral well section to determine distance of well to nearest conductive zone as part of the oil-water contact tracking. All available data - logs, cuttings, reservoir pressures and production data - was incorporated and used to validate fluid contacts data because of the impact of landing depth relative to the fluid contacts on oil recovery. Simulation results and operational constraints were used to set acceptable production limits to ensure delivery of target reserves.
All the four wells have been successfully drilled and completed, with the wells landed successfully within the thin oil column, at the optimized distance from the fluid contacts, with the wells producing at &lt;0.55 percent water cut. Initial production performances of the four wells are in line with static and dynamic assessment forecasts.
Lessons learned and challenges encountered during this development are also captured in this paper.
Cost Effective Appraisal Strategy Using Decision Tree Analysis for Optimal Field Development Planning
Authors: Awasthi Amit , Okonkwo Arinze , Afulukwe Chuks , Effiom Oghogho 
Published: July 2017

Abstract
Project B, consisted of five discrete subsurface elements; Remaining developed volumes, Infill opportunities, Resources in THIN-BED and Exploration prospects. These subsurface elements were at different levels of technical maturity and were planned into a single project maturity timeline with shared i(mpact on facilities. Based on level of technical maturity, two of the subsurface elements (THIN-BEDs, and Exploration prospects) were considered as requiring an appraisal plan to further mature their development options.
In anticipation of "lower for longer" oil price scenario, the appraisal strategy for the discrete elements was integrated and designed utilizing decision tree analysis. The appraisal strategy was developed for the immature subsurface elements, consisting of a variety of appraisal methods, each cost effectively geared towards fit for purpose data acquisition to mitigate the key uncertainties and enable further oil development in the field. Decision tree analysis for each of the immature subsurface elements, describing the possible outcomes with associated probability of success, was performed including fit for purpose economic analysis to understand & decide the value add and timing of appraisal.
This integrated appraisal strategy including decision tree analysis; provided the basis and strong logic to decide whether the appraisal is worthwhile and when is the most optimal time to do it.
This methodology demonstrates how the quality decision around field development planning could be made by using decision tree analysis to evaluate the value of the components, using associated uncertainty around estimated ultimate recovery. Furthermore, this analysis also is utilized to understand the timing of appraisal vis-a-vis the overall field/project development.
Comparative Approach to Relative Permeability Predictions
Authors: Mamudu Abbas , Taiwo Seun , Olafuyi Olalekan 
Published: July 2017

Abstract
Based on Welge's solution of the flow equation, a method (JBN technique) to calculate the individual phase relative permeabilities from displacement data was developed for the first time in 1959. It's the most commonly used data reduction method for obtaining relative permeability relationships from unsteady state data. Similar to the Welge method, differentiation of data is required and negligible capillary end effects are assumed when using the JBN method. To apply the JBN method, information on pore volumes of fluids injected and produced, the pressure drop across the porous medium and fluid viscosities is needed. This method generally gives relative permeabilities over a fairly small saturation range, which varies depending on the relative mobilities of the flowing fluids. In order to improve the results of this method, many researchers have come up with different techniques in their JBN analysis including the cubic spline numerical modeling technique (CSNMT) discussed in this research. This paper presents relative permeability data obtained from comparative analysis of the JBN method with different approaches. The differentials of second order Lagrange interpolating polynomial and cubic spline numerical modeling technique (CSNMT) were all considered in the JBN analysis. The relative permeability curves were then analyzed and the best method was chosen. The results of all the different methods employed in the JBN analysis do not match perfectly throughout the entire saturation range. The errors in the use of the differentials of second order Lagrange interpolating polynomial on more than three data point are very substantial. The results obtained from the application of cubic splines are more representative of the relative permeabilities from the field cores.
Gas Development in an Emerging Economy: Nigerian Case Study
Authors: Tahir Salahuddeen M. , Udezi Edwin E. 
Published: July 2017

Abstract
Nigeria aims to stimulate its economy by taking advantage of its gas reserve base to drive power generation and industrial growth. Several steps have been taken to achieve this. The study aims to identify the impediments to the desired results and proffer solutions to fast track the implementation of existing policies and structures.
To identify the current challenges militating against fast tracked gas development for the economic benefit of Nigeria, one needs to appreciate the successes gained so far by the nation. The gas industry pre development of the Nigeria LNG Project is considered. National power generation data is presented pre and post the advent of gas generating power plants. National gas demand data over a 20 year period is analyzed and compared to reserve growth. Gas midstream infrastructure pre and post approval of the Nigerian Gas Master Plan (NGMP) in 2008 is identified and compared. Effects of implementation of the commercial frameworks for upstream development and the Gas Master Plan are also analyzed.
Although a lot of successes have been recorded by the country, certain impediments have hampered the desired national economic growth. The following although still existing, are being addressed by the various stakeholders; Gas supply issuesPSC Gas TermsFunding challengesNon alignment of priorities by NNPC's different JV partnersCommunity issuesSecurity issuesCompeting projects by prospective investorsNon passage of the PIGBPolicy somersault
The paper analyzes the challenges and proffers innovative solutions towards addressing the issues. These solutions will not only help to provide a different line of thought for policy makers and other stakeholders in the Nigerian oil and gas industry but will also provide a sort of "lessons learnt" for other developing countries with recent oil and gas finds to fast track the development of their gas industry thereby achieving the desired economic growth.