bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Semiempirical Model for Rate of Penetration with Application to an Offshore Gas Field
Authors: Etesami Danial , G. Shirangi Mehrdad , Zhang W. J. 
Published: August 2020

SummaryIn this paper, we present an accurate semiempirical rate of penetration (ROP) predictive model for polycrystalline diamond compact (PDC) bits. Our model is inspired by the model of Bourgoyne and Young (B&Y) and follows an exponential form with 10 different drilling functions to account for various factors affecting ROP in drilling operations. We extend the B&Y model to the PDC bits and discuss that a different predictive model should be obtained for each formation. On top of the factors included in the original B&Y model, our model accounts for parameters such as downhole motor, equivalent circulating density, mechanical weight on bit (WOB), and wellbore inclination. In particular, we incorporate the effect of equilibrium cuttings bed thickness and downhole cuttings concentration in the ROP model. The parameters of the model are obtained using multiple regression analysis with the field data. The importance of obtaining a formation-based ROP model is tested and verified with field data, and an algorithm to determine the parameters for new data is provided. The model can be incorporated in a framework to obtain an optimal well plan for a new well or for prescribing optimal operational parameters for well planning and real-time drilling operations. The prediction performance of the proposed model is also evaluated in various formations for several test wells across an offshore gas field. Our results indicate that the proposed model is able to predict the drilling ROP with an accuracy of more than 90%.
Experimental Determination of Protein Enzyme Bio-Surfactant Properties for Enhanced Oil Recovery
Authors: Morgan Anthony , Akanji Lateef , Udoh Tinuola , Mohammed Shaibu , Aggrey Nkrumah Wilberforce , Sarkodie-Kyeremeh Justice 
Published: August 2020

Abstract
The properties of Protein enzyme biosurfactant, a green-enzyme, water-based inert-enzyme generated from the DNA of microbes that eat oil was studied to ascertain its applicability in EOR processes. A light crude oil of 0.908 g/cc at 22°C density and 53.87 cp viscosity was used in this study with a kinematic viscosity which was variable between 90.654 mm2/s to 13.7544 mm2/s between temperatures of 22.5 °C to 70 °C with a measured surface tension of about 35 mN/m. The bio-surfactant yielded a CMC value of 0.02 wt.% which is comparable to reported CMC values of other surfactants. The least IFT value measured was 4.0 mN/m, which is very high for a very efficient and effective residual oil recovery (an ultralow IFT of about 0.01mN/m is required of which was achievable by Rhamnolipid a bio-surfactant studied alongside Protein Enzyme in this work). Ionic (0.083M to 3.0M) and temperature (23 to 70 °C) effects did not have much influence on the activities of bio-surfactant, thus quite stable within such conditions. The protein-enzyme has the ability to form a Winsor type III emulsion and stable over the period of time studied. Adsorption was noticed especially with higher bio-surfactant concentrations but tends to be stable over time.
The Benefits of the Installation of Live Gas-Lift Valves During the Initial Well Completion Phase of a Well, Addax Petroleum Development Company as a Case Study
Authors: Ifediora Emmanuel Eberechukwu 
Published: August 2020

Abstract
The installation of dummy valves with the initial well completion for gas lifting wells has been a popular practise in the industry. These dummy valves provide a barrier between the annulus and the tubing during the well completion phase to the test the tubing and annulus independently after the well is flanged up. These dummy valves are later changed out for live valves in preparation for lift gas injection when the reservoir energy becomes too low for the wells to flow or when the desired production rate is greater than the reservoir energy can deliver due to water production. Whereas this completion method has endured, it has escalated the clean-up cost, and maintenance cost of these wells because the intervention operations for gas lift changeout are often time consuming and costly.
To minimise the above costs due to the installation of these dummy valves during the initial completion phase, Addax Petroleum Development Company adopted the use of live valves during the initial completion. After completing the well with brine, it requires to be underbalanced to unload the brine and clean out before producing to the sales line. For under saturated reservoirs and depleted reservoirs, coil tubing with Nitrogen injection had been used to initiate the underbalance for the well clean up because of its low density and high-pressure characteristics. Today to further reduce the well clean-up cost, Addax Petroleum Development Company now pumps Nitrogen or lift gas through the casing-tubing annulus and the live gas lift valves to under balance and off load the well.
Also, with the introduction of live gas lift valve installation, the cost of the dummy valve changeout, with consequent production deferment during the intervention process has been eliminated.
This paper highlights the benefits Addax Petroleum Development Company has derived from the installation of live gas lift valves with the initial completion by reducing the completion and clean-up cost in each well completed, and the consequent elimination of well intervention cost for a gas lift changeout.
Investigating the Nexus Between Nigerian Rig Rates and Crude Oil Prices
Authors: Ojukwu Kelechi Isaac , Ajienka Joseph , Dosunmu Adewale , Iledare Omowumi , Ibe Chidi 
Published: August 2020

Abstract
This study set out to investigate how Nigerian oil rig rates respond to oil price fluctuations, and the lag between them aimed at developing models for forecasting land, swamp and offshore rigs rates in Nigeria.
The research methodology involves application of Ordinary Least Squares regression to develop models that can predict land, swamp and offshore rig rates, which can be used in the Nigerian market. Firstly, Brent crude oil prices are exogenous to Nigeria, whilst land, swamp or offshore rig rates are endogenous. Furthermore, these exogenous variables are regressed with and without lag to test the response time between the cause and its effect.
A striking relationship is observed between these independent variables similar to global trends. Like other countries, the Nigeria oilrigs count trends along with Brent crude oil price. However, a 3-4 months lag exists between Nigerian rig rates and oil prices. Furthermore, the model estimation using one-year lag seems to show more accuracy in matching the historical rig rates and the more expensive the rig, the wider the margin caused by oil price changes. This confirms the possibility to predict Nigeria rig rates and perhaps, well costs from oil price forecast.
Using Limited and Cheap PVT Data to Reduce GOC Uncertainties in Reservoirs with Unknown GOC
Authors: Okoh Oluchukwu M. , Lawal Kazeem A. , Yadua Asekhame U. , Odude Adebayo , Anyanwu Obinna T. , Ovuru Mathilda I. , Eyitayo Stella I. , Pelemo Bosun , Akewusola Taye , Matemilola Saka , Ramaswamy Sunil , Nwaeri Edwin 
Published: August 2020

Abstract
There are direct and indirect methods to define a gas-oil contact (GOC) in a petroleum reservoir. The direct method requires drilling a well to penetrate prospective fluid contacts. The indirect methods, which include, compositional grading simulation (CGS), do not require evaluating prospective GOC with a dedicated well. However, the CGS technique is currently deemed not applicable in cases of limited pressure-volume-temperature (PVT) dataset.
By exploiting a new framework developed by Okoh et al. (2020), this paper demonstrates the applicability of CGS to petroleum reservoirs characterized by limited PVT dataset. This method entails estimating the degree of under-saturation of a given fluid sample at a known sample depth. Using known fluid gradient and estimated saturation pressure gradient of the fluid sample, this degree of under-saturation is converted to its equivalent depth to estimate a potential GOC within a connected reservoir. Empirical models for estimating saturation pressure gradient and bubble-point pressure of an oil sample at in-situ conditions are presented. Considering the need for a reliable estimate of the in-situ bubble-point pressure, different bubble-point empirical models are examined for their suitability and accuracy.
Several examples of saturated and undersaturated reservoirs from the Niger Delta are used for validation tests. Overall, the bubble-point correlation by Ikiensikimama and Ogboja (2009) was found to be the most appropriate for the intended application. Additionally, the validation tests confirmed the robustness of the proposed method for predicting potential GOC in petroleum reservoirs that have limited PVT dataset. While the scope of validation of this paper has been limited to the Niger Delta, we expect the proposed method to perform satisfactorily in the treatment of similar problems in other basins.
Creating a Digital Twin of Part of the Earth Subsurface through Reservoir Navigation Service
Authors: Imomoh Victor Bello , Toyobo Oluwaseun , Okafor Rosemary 
Published: August 2020

Abstract
A digital twin can be said to be a virtual model of a physical body, living or non-living. By bridging the physical and the virtual model, data is transferred seamlessly allowing the virtual model to exist simultaneously with the physical body. It is, therefore, a digital replica of a possible and actual physical assets, systems, places, persons or devices.
The success of any reservoir navigation service involves team effort from many disciplines that include engineering, well planning and design, geological study and a host of other fields. This usually results in lots of digital data from planning to execution, as well as a post-project stage where best practices are adopted for the next project.
This paper will focus on showing how the reservoir navigation service earth model can be seen as a digital twin of a section of the earth and how advances have already been made in this light to aid in creating a perfect digital twin of the earth for geosteering purposes.
Production Enhancement Using Micro-Emulsion Technology in Ogini and Isoko Fields
Authors: Ajao Wale , Onwuchekwa Chukwuma , Isiba Ezinwanneakolam , Oke Oluwatobi , Ideh Matthew , Agbaroji Victor , Okon Willie , Ageh Ebenezer 
Published: August 2020

Abstract
Near wellbore impairment result from various factors such as mud invasion, filter cake deposition, and fines migration in producing fields. Micro Emulsion Chemistry, other than the traditional acid stimulation presents a new and novel remedial treatment for near wellbore impairment. A microemulsion is a typical Newtonian fluid system distinguished from emulsions owing to its being stable thermodynamically and self-organizing.
This technical paper explains the process of candidate selection, data gathering, job execution, and resultant crude oil gain from deploying micro-emulsion technology (MET) on some strings in the Ogini and Isoko fields. The fields have different and unique challenges. While the Ogini field has characteristic heavy oil and viscous crude, the Isoko field has wax deposition challenges. Deploying MET treatment in both fields yielded record-breaking results and productivity (PI) improvements in multiple folds. A total of 3,500 bopd (incremental oil) was achieved from treatment on four strings in both fields.
Allocation of Processed Natural Gas Streams Under a Gas Tolling Arrangement
Authors: Kanshio Sunday , Tahir Salahuddeen M. 
Published: August 2020

Abstract
Gas tolling is a business model where the owner of the tolling plant (a gas processing plant) receives raw gas from multiple suppliers, processes the gas and returns the products to the suppliers of the raw gas for a fee. This study investigates the effect of hydrocarbon commingling on the output products quantities of a conceptual gas tolling plant. The study also compared three allocation methods, namely, proportional, shrinkage factor and composition-based allocation method. In a situation where there are multiple suppliers, the raw gas composition and flowing conditions would vary considerably. In the processing plant, the gas undergoes phase change due to varying physical properties and plant operating conditions. The proportional and shrinkage factor method requires fewer measurement data but do not obey the principle of equitability in the allocation of the products streams. The composition-based allocation, which was carried out using the UniSim Design Production Allocation Utility, allocates the products streams equitably by tracking the phase changes in response to any changes in flowing conditions of the contributing sources.
Probability Approach to Casing Design Using Monte Carlo Simulation
Authors: Muoghalu Amalachukwu , Ansa John , Dosunmu Adewale 
Published: August 2020

Abstract
Casing design plays an important role in the successful drilling of a well and accounts for a substantial percentage of well costs. The goal of casing design is to get an optimal design that will withstand stress and other factors that affect casing throughout the lifetime of the well. The conventional approach to casing design uses a deterministic working stress design (WSD), where minimum strength requirements of the casing are determined by comparing casing strength to the magnitude of severe accidental loads that may occur during the lifetime of the well. Uncertainties in the load and strength of the casing are accounted for by multipliers called safety factors (SFs) that are mostly based on experience and do not reflect the probability or consequence of the different casing failure modes. This approach may result in overly conservative casing designs, or design requirements for severe conditions that are expensive, leading to higher well costs.
In this paper, the Monte Carlo Simulation (MCS) method is applied to casing design, where uncertainties in casing loads are considered explicitly by assigning probability distributions to safety factors that affect design loads. As the MCS method predicts the casing safety factor probability, it gives a better view of the real uncertainties involved in the design. Acceptable probabilities of casing design load can be selected based on the cost and operating conditions the casing will undergo; thus, a probability approach to casing design is more flexible as it allows an explicit uncertainty-consistent designs compared to traditional working stress designs.
Improved Correlations and Predictive Models for Nigerian Crude Oil Pvt Properties Using Advanced Regression and Intelligent Techniques
Authors: Uzogor Kingsley , Akinsete Oluwatoyin 
Published: August 2020

Abstract
Calculating reserves in an oil reservoir and also the determination of its performance and economics needs a sound knowledge of the fluids’ physical properties. Bubblepoint pressure, Oil FVF at bubblepoint, solution GOR and compressibility are of primary importance in material balance calculation. Ideally, the laboratory measurements of PVT properties are the primary sources of PVT data gotten from laboratory studies of the samples collected from the wellbore or from the surface. However, such experimental data are not always available mainly due to unreliability of the data from samples or that samples have not been taken as a result of cost saving as the operation can be quite expensive. It therefore became pertinent to be able to predict these properties in the absence of the experimental data. Several correlations have been developed to enhance this prediction but, unfortunately, these correlations are highly region dependent and rarely works well in different regions since they were developed with data from particular regions.
The objective of this study is to develop better performance correlations and predictive models for the Nigerian crude oil PVT properties using linear and non-linear multivariate regression techniques and supervised machine learning techniques. This study focuses on predicting bubblepoint pressure, Pb, oil formation volume factor at bubblepoint, Bob, and solution gas-oil ratio, Rs, as functions of the reservoir temperature and the oil and gas gravities.
In this study, evaluation and tuning/recalculation of coefficients (using linear and non-linear regression analysis) of some of the best PVT correlations to estimate the desired PVT parameters and employing the KNN and the Random Forest algorithms to develop better PVT models for the Niger Delta region, were performed. After adequate pre-processing, the gathered dataset was divided into training and test datasets by random sampling. Average absolute Relative Error, Root Mean Square Error and the Correlation coefficient, R are the main loss functions employed to evaluate and compare the developed models with the conventional correlations.
The new models showed much better performance as regards the Niger Delta crude PVT properties. With respect to the best performing conventional correlations for the Nigerian crude, the new models decreased the RMSEs by 72%, 61.1% and 83% and increased the correlation coefficients by 35%, 7.2% and 26.9% for the bubblepoint, oil formation volume factor and solution gas-oil ratio respectively.
Information Management: Key Strategic Tools to Unlock the Barriers to Marginal Oil Field Development in Niger Delta
Authors: Oruwari Humphrey Otombosoba 
Published: August 2020

Abstract
The aim of the study was to evaluate information management as key strategic tools to enhance marginal field operations in Niger Delta. Using literature review and case study of marginal fields operating in the region. The significant values of information are examined, against the background of barriers to marginal oil field development. Specifically the inability to develop some of the fields is traced to information asymmetry in oil and gas operations and the inability of the system to manage and use existing information. Understanding the strategic roles of information will assist stakeholders in establishing its usefulness as a tool for leveraging on competitive advantages in order to improve the bottom line. Some recommendations are made as what should have been done to improve marginal field operations among which are: Educate communities about oil companies’ obligations and the Department of Petroleum Resources (DPR) should develop and launch a web based portal that advertises available geo-data on a block by block basis.
Implementation of a Well Integrity Management System in the Nigeria Agip Oil Company Joint Venture NAOC JV Using Peloton WellView Software
Authors: Adebajo Adeyemi , Emuchay Daniel , Adeyinka Olubunmi , Oseni Damilola , Onasanya Babafemi , Wopara Promise , Onyekwere Victor , MacDonald Chris 
Published: August 2020

Abstract
The NAOC JV, comprising 20% NAOC, 20% Oando Oil Ltd, and 60% NPDC working interests, owns over 400 wells in OML 60 - 63 within the Niger Delta region of Nigeria. To ensure well integrity and protect property, lives and the environment throughout the well life cycle, first and second line wellhead maintenance activities involving greasing, leak testing, function testing, repair and replacement of tree valves and down-hole safety valves (DHSV) are carried out based on approved well integrity programs.
The Well Integrity Management System (WIMS) provides guidelines for first line wellhead maintenance activities frequency in line with API recommendations; second line wellhead maintenance is carried out on an as needed basis to ensure the integrity of all wells throughout their lifecycles.
WIMS implementation using WellView is a smart well integrity surveillance system that generates and sends auto emails to selected users on well integrity issues based on preset criteria for leak rates and casing pressure limits. This has been effective in timely identification of issues before they become major problems. It also triggers proactive actions on critical wellhead system components that are nearing failure based on results of analyses.
This paper describes the workflow, strategy adopted by our IT team, coding developed by Peloton WellView consultants and issues encountered in achieving this feat; current issues and proposed solutions are also discussed.
Uptime Improvement for Selected Intermittent Oil Producers
Authors: Nnanna Erasmus , Ezekwugo Joseph 
Published: August 2020

Abstract
Production wells normally experience different phases of life, starting with the initial ramp-up phase after drilling and completion, through the plateau period and finally to the decline phase. The tail-end of the decline phase often present with intermittent production behaviors requiring ‘tender-loving care’ to maximize production performance. Wells normally quit in this phase of production and may require a period of pressure build-up before being re-opened to production. Primary reason for this behavior is increase in watercut or decrease in reservoir pressure or a combination of both. Typically, intervention actions on intermittent wells are based on initiation of artificial lift, water shut-off or production in a cyclic manner if there is no scope for these. The typical production cycle of a cyclic well goes from normal production through unstable production (fluctuating wellhead pressures) to eventually quitting. Whereas every naturally producing well eventually quits, paying close attention to operating conditions of cyclic wells can enhance their availability and unlock significant production volumes for the asset.
SPDC, a Joint Venture Organization in Nigeria with oil and gas wells spread across the Niger Delta, has about 64 intermittent producers; 54 oil wells and 10 gas wells. These producers are approaching the tail-end of their lives and therefore produce in a cyclic manner-with uptime and downtime cycles. Driven by the desire to improve integrated production system capacity (IPSC), there has been a renewed focus on this category of wells towards improving their uptimes. An approach deployed to improve the uptime (availability) of these wells involved the optimization of well operating envelopes. This implied moving the operating points of the wells to the stable region of inflow/outflow performance curves after challenging the basis for the current operating envelopes. This led to the adjustment of choke sizes, increase/decrease of gaslift injection rates and relocation of chokes from wellhead to the manifold.
Five pilot wells were selected for this project with operating envelope reviews carried out and adjusted based on detailed well performance analysis. The result is cumulative average uptime of 256 days versus historical cumulative average of 91 days (more than 100% improvement in uptime) for the 5 wells. The production gains achieved within a period of 3 months was over 50,000 bbls at no extra operating cost and no additional technical risk.