bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effectiveness of High-Performance Water-Based Spacer Systems for Curing Lost Circulation in Permeable Reservoirs During Cementing Operations
Authors: Adesanya Olukayode , Mofunlewi Samuel S. , Ighodaro Osaze 
Published: July 2017

Abstract
Geological components of reservoirs vary across geographic regions. A typical reservoir environment comprises various characteristics: the kind of hydrocarbons it contains, the level of consolidation and unconsolidation, formation porosity, permeability, pore and fracture pressure characteristics, depleted reservoirs and many more. It is common to observe lost circulation during the drilling and cementing phases of a well spudded in permeable or unconsolidated reservoir environments. Various lost circulation prevention techniques can be deployed to minimize losses. These techniques include incorporating the best drilling practices to equipping the mud or cement system with effective lost circulation control materials.
Losses experienced during the drilling or cementing phases of oil or gas wells can result in an underbalanced reservoir environment that can ultimately have devastating consequences on drilling activities. Losses can either be minor or partial to complete losses, depending on the unaccounted volume lost into the formation at any specified period of time. This situation is usually monitored by accounting for the volumes of drilling mud/ fluid pumped in hole with respect to the volume out at the mud pits. In the cementing phase, uncontrolled losses often lead to the reduction of the annular height of cement behind the casing, resulting in poor zonal isolation.
Cementing applications have been improved to control losses by integrating a lost circulation control system in either or both the cement slurry or/and spacer system. This paper showcases the efficiency of a high-performance water-based spacer system deployed on a well section where lost circulation was a major challenge. The paper presents how this spacer system effectively controlled losses and enhanced zonal isolation while achieving the desired annular height of cement and an excellent cement bond evaluation log.
Fit-For-Purpose Development Plan for FLO Reservoir Sand with Focus on Resolving Reservoir Connectivity and Fluid Contact Uncertainties
Authors: Nwabia Francis , Osagie Ehiosu , Eghobamien Liberty , Nwonodi Chike , Sonde Adenike , Awa Chukwunweike 
Published: July 2017

Abstract
FLO reservoir in the depth range of 8225-8780 ftss has an unknown nature of compartmentalization, unknown fluid property and also five well penetrations with none encountering OOWC (original oil water contact). Resolution of these uncertainties in this study created platform for the reservoir development in terms of growing production and increasing the reservoir ultimate recovery. This paper therefore focuses on an integrated approach of resolving uncertainties associated with key reservoir evaluation parameters to deliver a fit-for-purpose development plan of the reservoir.
A multidisciplinary approach, involving integration of: PVT (Pressure Volume Temperature) Property estimation, Fault Seal Analysis (FSA), Petrophysical analysis and Dynamic simulation were employed to pin down these uncertainties in fluid contact and connectivity across blocks K, L and M within FLO reservoir.
PVT property estimation was used to capture the phase behaviour of FLO reservoir fluids. While FSA, which relied on the degree of throw thickness and lithologic juxtaposition, was used to validate connectivity across fault blocks in FLO reservoir. Possible base case contact for the two producing blocks in the reservoir was established through dynamic reservoir model calibration by history matching for 41 years of production history.
Results obtained from FSA, pressure profiles, sand-to-sand juxtaposition and dynamic history matching all combined showed an established hydraulic communication between reservoirs block K & M and also blocks K & L. The dynamic history matching with adjustments within physical meaning of basic history matching parameters realized 8525 ftss and 8810 ftss for POWC (present oil water contact) of the reservoir blocks K and M respectively. With these uncertainties resolved, different tests of development concepts were conducted and checked for economic viability and this showed that a "Do Nothing" approach with recovery of 3.6 MMstb should be adopted for FLO K and a "New Well" with recovery of 1.92 MMstb be drilled to develop FLO M.
Effective Real-Time Pore Pressure Monitoring Using Well Events: Case Study of Deepwater West Africa - Nigeria
Authors: Onyeji J. A. , Adebayo A. A. , Stafford T. W. , Ekun O. A. , Onu H. , Nwozor K. K. 
Published: July 2017

Abstract
Geomechanical related drilling problems have always been the major cause of geologic non-productive time (GNPT) in drilling operations (complex and conventional wells) especially in deepwater basins, where billions of dollars are being spent while searching for solutions to drilling problems and developing remediation plans. Thus, real-time pore pressure monitoring is critical to ensuring safe and successful drilling operations. Typically, the only information available to the drilling engineer prior to well spudding are offset wells and predrill models (1D or 3D) built from offset wells data and other sources (regional, sub-regional, seismic etc.) and no two (2) wells are ever the same in terms of behavior, then the need for real time pore pressure (PP), Fracture Gradient (FG) and Wellbore Stability (WBS) monitoring in ground-truthing and calibrating the predrill model cannot be overemphasized. This paper describes how modern technology, innovative approaches, monitoring well behavior and effective communication helped in meeting the challenges of real time pore pressure and fracture gradient surveillance while drilling in environments with very narrow drilling mud weight windows, and where there is limited information on the formation pore pressure, subsurface rock properties, in-situ stresses and basins with little to no offset well information. Integration of multiple data sets [appropriate logging while drilling data (LWD), drill cuttings, drilling parameters, gas in mud, equivalent circulating density (ECD) and equivalent static density (ESD)] and well behavior/events to support and calibrate predrill petrophysical log-based pore pressure prediction models significantly aided in drilling two complex wells safely and successfully to the target reservoirs in cost effective manner in the study area. Mechanical cavings and reamer affected cuttings were easily differentiated from normal drill cuttings, and potential kick predicted even in the absence of pipe connection gas; where there is no sign of underbalanced drilling using predrill pore pressure/ fracture gradient/wellbore stability (PPFG/WBS) petrophysical logs-based model. The model formed the basis for the critical drilling operations decisions taken in these case studies; mud weight increase, setting intermediate casing shallower than planned, and well deepening. Factors such as abnormal high rate of penetration (ROP), drilling mud properties, high temperature, salinity and calcite cementation affect petrophysical data, thus relying only on the logging while drilling (LWD) data such as gamma ray, resistivity, and sonic logs for real-time pore pressure and fracture gradient analysis, especially when drilling deep wells is not recommended. The innovative approaches presented in this paper via its workflow compensate for potential limitations of LWD data.
Integrating Modular Refining and Marginal Field Operations Under Proposed Fiscal Terms – Is Value Possible?
Authors: Gbakon Kaase 
Published: July 2017

Abstract
This paper aims to address the question of how much economic value can be derived by the integration of modular refining in the development plan of a field qualified as marginal within the Nigerian petroleum industry context. Furthermore, the economic value sought by the integration will be weighed against the backdrop of current fiscal provisions and then compared with provisions for refineries that have historically been offered in successive versions of the PIB (Petroleum Industry Bill) – that of making the incentives for gas utilization projects found in Section 39 of the CITA (Corporate Income Tax Act) available for refinery projects.
For this evaluation, an onshore marginal field with reserve size 150MMBOE, and crude oil API of 38°API is assumed to be developed with an estimated CapEx of $900Million under a concession lease arrangement by a new entrant. The production from the field is to be monetized by the deployment of an optimally sized modular refinery configured to produce Gasoline, Kerosene, Diesel and Gasoil. A spreadsheet economic model is built which considers the upstream and refinery developments as fiscally separated and test the viability of the integrated project at the current terms and the historically proposed PIB2009 and PIB2012 terms. Sensitivities are performed around oil and product price, fraction of production refined, CapEx, OpEx.
Under the current terms, at $45/bbl and $2.70/mscf and assuming 100% production is refined on the asset, the integrated project yields an IRR of 12% compared with 15% under the proposed PIB2009. Furthermore, between the 2009 and 2012 proposals, the integrated project returns a lower IRR of 14% under the PIB2012 than the 15% observed for PIB2009. Sensitivity analysis further reveals that at any given oil price, the integrated project value improves with increased fraction of production utilized for refining. For example under current fiscal regime, at $45/bbl, NPV10 improves from ($94Mln) at 40% crude utilization to $235Mln at 100% crude utilization, with a breakeven utilization rate of 60%.
Artificial Neural Network Modelling of Viscosity at Bubblepoint Pressure and Dead Oil Viscosity of Nigerian Crude Oil
Authors: Adeeyo Yisa A. , Saaid Ismail M. 
Published: July 2017

Abstract
Reservoir engineering calculations required reservoir fluid viscosity data. In the absence of reliable experimental data, empirically derived correlations are used to predict the PVT property. However, several viscosity correlations in the literature were developed using regional data with limited accuracy and applicability.
Artificial neural network (ANN) is a computer model that attempts to mimic a simple biological learning process and simulate specific functions of human nervous system, a new computation algorithm that could be used to develop more robust and reliable model for generating PVT data. It is an interconnection of nodes, called neurons.
The authors have evaluated the industry widely used viscosity correlations using Nigeria crude oil data and explored the use of neural network in estimating viscosity at bubblepoint pressure and dead oil viscosity with the aim of getting a more accurate oil viscosity predictive model compared to widely used correlations in the literature. This study used the ANN backward propagation procedure with the Levenberg-Marquardt algorithm for the optimization procedure for both the viscosity at the bubblepoint pressure and dead oil viscosity models.
The number of data set used for viscosity at the bubblepoint pressure is 1809 and dead oil viscosity is 1750. A number of neural network hidden layer designs were considered and tested. Each successful trained model was tested to ensure that overfitting does not occur and can predict output from the inputs that were not seen by the model during training. Sixty percent of the data was used to train the network, twenty percent to cross-validate the relationships established during the training process and the remaining twenty percent to test the model.
The results of artificial neural network model for viscosity at bubblepoint show that the model gives higher accuracy compared to the published correlations with average absolute relative error of 11.05 and coefficient of correlation of 0.98. Besides, the dead oil viscosity neural network model shows a substantial improvement over correlations with average absolute relative error of 12.6 and coefficient of correlation of 0.91.
Integrated Data Analysis: Key to Understanding the Reservoir
Authors: Obi Chinyere C. , Hassan Yusuf M. , Akenobo Charles 
Published: July 2017

Abstract
Technology advancements over the years have improved our understanding of the subsurface. This paper focuses on how integration of available geological and engineering datasets was used to de-risk the geological and petrophysical uncertainty of Reservoir B-1.1 in Oredo field in Niger Delta.
The oil reservoirs in this field experienced late fair aquifer support. However, the producing gas reservoirs exhibit volumetric drive behavior so far. Analysis of logs, production, pressure and PVT data were carried out. Fluid and material balance (analytical) models were built and fluid model was tested for validity. There was 80% difference between the material balance volume and the static model volume. The material balance volume is supported by historical Bottom Hole Pressure surveys and recent wireline formation test acquired from a sidetracked well in the field. This wireline formation test shows substantive pressure depletion across the reservoir of interest, which can be attributed to production activities from the existing conduit. Based on the geological analysis, there is no evidence of compartmentalization to account for the pressure and production behavior of the well producing from this reservoir. Sensitivity and uncertainty analysis on selected parameters were carried out on the base case geological/static model to validate the Hydrocarbon in Place volume for history matching and performance prediction.
The dynamic simulation run under uncertainty validated the material balance volume. This led to the revision of the petrophysical evaluation and update of the static model.
Improved Horizontal Well Delivery Using Advanced Geosteering Technology – The Ogini Field Example
Authors: Awa Chidi Uka , Bola Adelanke Gregory , Oke Oluwatobi Martins , Jaiyeoloa Jeffrey Ifihan , Chieke Chidi Anselem , Obi Chinyere , Olagunju Oluwatoyin 
Published: July 2017

Abstract
Over the years horizontal wells have been drilled using the conventional approach. Failure to drill and place the horizontal drain section optimally was becoming a common occurrence especially in a thin reservoir. The search for processes and procedure to mitigate this failure led to the creation of Well Placement (Geosteering) Process. This process was defined (Rogger Griffit 2009) as "The planned interactive placement of the well-bore using geological criteria and real-time measurements".
Using geological criteria in real time requires technology capable of adequately delineating the structure and at the same time providing Petrophysical properties of the reservoir in real time. These needs led to development of key Logging While Drilling (LWD) technologies for high angle and horizontal wells. Over the years, the Geosteering methods have evolved based on available LWD technologies. These methods have been classified as (i) Reactive (Basic log correlation), (ii) Proactive (Distance to Boundary) and (iii) Strategic Reservoir mapping).
The objective of this paper is to demonstrate how technologies were utilized in Ogini campaign to optimally position the production section of the wells close to the reservoir top, so as to delay onset of water, reduce intervention cost and to increase ultimate recovery. To achieve these objectives despite high risks due to structure and stratigraphy, two well placement methods / technologies were deployed in the landing and within the production section of the reservoir.
Real Time Image/dip technology was utilized in the landing section to aid the landing while monitoring the apparent formation dip and a Multilayer Distance –to-Boundary technology (PeriScopeHD*) was used to optimally position 5 horizontal wells close to the tops of each of the target reservoirs in Ogini field.
Identification and Cost Effective Mitigation of Calcium Carbonate Scaling in Gas Field - A Typical Case Study in Niger Delta
Authors: Abuah Nnamdi L. , Olugbenga Daodu , Adam Sedqwick M. , Chiejina Leo , Bamidele Taiwo , Onuigbo Nweze C , Stella Egwim , Florence Ifeanyi-Onah , Onyedikachi Okereke , Bassey Imaobong , Noah Ebogomo , Igban Kalu 
Published: July 2017

Abstract
Beta Integrated Oil and Gas plant is the major supplier of domestic gas to the Lima power plant which provides 16% of the available power to the Nigerian national grid. Efforts are made to ensure that down times in the plant are reduced because of the huge impact to domestic gas supply in the country. Between 2014 and 2015, multiple tripping had been observed on the transfer pump at the Beta gas plant. Laboratory analysis of the recovered solid deposits in addition to scale simulations of the hydrocarbon fluid confirmed the presence of calcium carbonate scale (85.2%wt). Although the culprit well was identified, a cost-effective surface chemical solution was immediately deployed upstream of the facility which significantly reduced the export pump downtime due to scaling and clogging. The overall treatment option adequately mitigated the calcium carbonate scale observed and also led to significant savings in pump maintenance of about a million dollars.
This paper will be discussing the problem and underlying restrictions faced by the multidisciplinary team, problem solving approaches considered as well as the solution employed by deploying Phosphate Ester based chemical scale inhibitor.
The scale inhibitor is specially formulated to prevent the formation of calcium carbonate, calcium sulphate, barium sulphate and strontium sulphate scales in producing wells, water injection systems and saltwater disposal systems.
One major consideration in the choice and use of the product is the cost effectiveness of the product, its potency and suitability at effectively mitigating the calcium carbonate scaling in the gas plant. It was successfully qualified in the lab for use with MIC of 10-20ppm and has been previously deployed in our deep water facility. Laboratory tests indicate it is effective in produced water with iron and high bicarbonate content as is the case for Beta gas plant. In addition, laboratory tests indicate it does not encourage deposition of naphthenates in produced water as is observed with some phosphate based scale inhibitors. The product is also readily available in-country hence no long delivery lead time challenges, besides there is significant cost and logistics value to be realized from its deployment in Beta oil and gas plant.
Production Increase in an Onshore Oilfield Using a Rapid Screening and Multidisciplinary Approach
Authors: Okoroafor Esuru Rita , Obi Chinyere , Akenobo Charles , Dagogo-Jack Cyrusba D. , Nnebocha Ezinne , Okeke Uche , Arasi Quadri , Ogbidi Lymmy , Mezie-Okoye Somto 
Published: July 2017

Abstract
A natural phase in the life of oilfields is the maturation phase where the field undergoes all or some of situations as decline in pressure, increase in water and/or gas production, and fluid contact movement. Reservoir management practices require identifying these oilfield challenges and coming up with solutions to maximize production from such fields adapted to the uniqueness of the wells and reservoirs in the field.
This paper discusses a novel multidisciplinary and rapid screening methodology for identifying well intervention candidates. The methodology adopted to evaluate production increase opportunities was on field and well bases. Geology, Petrophysics, Reservoir Engineering, Production Technology, Production Engineering and Completions Engineering disciplines were involved in this study.
The field assessment started with the field production performance review using a production surveillance and forecasting tool. This was combined with a holistic field geological review of the static models and well logs on a shared-earth modelling software and a wellbore-centric data integration and interpretation software respectively. Based on the field assessment review, reservoirs were ranked based on remaining oil in place and cumulative production.
Results of the field assessment were then fed into the single well assessment phase where individual well performance was reviewed using the production surveillance and forecasting software. This production surveillance and diagnosis was done vis-a-vis a multidisciplinary workflow of integrating reservoir models, well logs, fluid contact interpretations, pressure data, historical production, completion designs and information from previous workover operations and well surveillance reports. This workflow identified possible candidates where well intervention could be done, the type of well intervention and production enhancement operations that could be deployed, and the order to which the interventions should take place based on cost and potential gains. However, to estimate the incremental production that could be derived from the proposed well interventions, a workflow coupling single well predictive modelling and production systems analysis was done, which was further used to rank the wells.
Implementing the recommendations from the rapid screening and ranking workflow resulted in incremental production of 3300 bopd from the few intervention operations executed. The results also validated the predictions made during the rapid screening study.
This paper thus demonstrates the added value in a multidisciplinary approach to screening and identifying candidates for well intervention, to extend the life of producing wells and ultimately increase field production.
Impact of PVT Correlations on Reserve Estimation: Reliability and Qualitative Analysis
Authors: Ireke Ireke Ukiwo , Princewill M. Ikpeka 
Published: July 2017

Abstract
Many correlations are currently being used to predict PVT properties in the oil and gas industry. This work thoroughly reviewed the works done by Standing (1947), Vasquez and Beggs (1980), Glaso(1980), Petrosky & Farshad (1993), Al Mahoun (1988), Kartoatomodjo & Schmidt (1994), Obomanu & Okpobiri (1987) and Ikiensikimama & Ogboja (2009). There were obvious discrepancies between these models and the experimental results mainly due to the fact that the models were built using data from the US and Middle East. Sequel to the discrepancies observed in these correlations, this works proposes a new model based on excel regression analysis to depict a more accurate value of the Oil Formation Volume Factor (OFVF) based on experimental results. The basis for comparison of the various correlations was Average Percent Relative Error, Average Absolute Percent Relative Error, Minimum Absolute Percent Relative Error, Maximum Absolute Percent Relative Error and Standard Deviation. This work utilized data from the Niger Delta and other relevant regions to modify or propose a correlation which will have a minimum error or standard deviation from the experimentally determined results. A total of 119 data sets (comprising of 833 data points) were collected and checked for accuracy. Quantitative analysis (reliability analysis) and qualitative analysis using cross plots was conducted on the seven considered literature correlations. Preliminary comparison of the performance of various correlations revealed Al-Marhoun to be the most accurate with an AAPRE of 2.669957%. However, using non-linear multiple regressions a new correlation for OFVF was which obtained significantly outperformed the other correlations. It provided a far much better Average Absolute Percent Relative Error of 2.4037%. From the volumetric approach of determining the reserve estimate, and the Stock Tank Oil Originally in Place (STOOIP) analysis, thus in conclusion, the developed correlation with minimal error in Bo had less impact on the oil originally in place and gave the most accurate STOOIP. A sensitivity analysis was carried out using @Risk™ Software, in order to quantify the impact of these variables on the overall estimate of Oil in Place.