bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simple Guidelines for Screening Development Options for Oil-Rim Reservoirs
Authors: John Idoko Job , Matemilola Saka , Lawal Kazeem 
Published: July 2019

Abstract
Given various competing alternatives, the rigorous evaluation of development options for oil-rim reservoirs can be challenging and computationally intensive. For quick and robust decision-making, an efficient screening method that accounts for the relevant static and dynamic properties of the reservoir of interest is desirable. Based on controlled numerical simulation experiments, this paper proposes simple screening guidelines for oil-rim reservoirs under the mutually exclusive development scenarios of (i) sequential oil-then-gas (OTG); (ii) concurrent oil-and-gas (COG); and (iii) gas-only development (GOD).
For simplicity, a two-level factorial design was used to create 17 experiments from a set of static and dynamic reservoir properties. A generic reservoir box model was then developed and used to conduct a total of 51 experiments. For each of the three development options, normalised surrogate models were developed for hydrocarbon recovery factor (RF) as a function of these static and dynamic properties.
For the specific box model and the parameter space examined, it was found that the performance of the OTG option is most sensitive to oil API (viscosity), vertical anisotropy, oil relative permeability and liquid offtake rate. The COG case showed oil API, vertical anisotropy, liquid offtake rate and oil relative permeability as the heavy hitters, while the GOD option returned oil rim thickness, relative permeabilities and gas offtake rate as the key drivers of reservoir performance.
Performance comparison of the three development options reveals that when reservoir properties are favourable to oil flow, OTG is the preferred oil-rim development option, while the GOD option is the most attractive when the reservoir is naturally less favourable to oil mobility. Although these guidelines provide indications of the most promising option, the final decision should be premised on further detailed studies, while considering both technical and non-technical factors that are peculiar to the specific project in question.
Impact of Geological Interpretation on Reservoir 3D Static Model: Workflow, Methodology Approach and Delivery Process
Authors: Agi Augustine , Gbadamosi Afeez , Junin Radzuan , Kampit Stanley Jaul , Abbas Azza , Gbonhinbor Jeffrey 
Published: July 2019

Abstract
The traditional method of geologic modelling requires the interpretation of geological sections during digitization. But this traditional method has its limitations, the main limits are; it is usually time consuming and the model produced is unique to each individual geologist interpretation and may not be easily replicated by others. This study proposes an alternative workflow method for modelling, constructing and interpreting 3D geologic static model with multi-source data integration. The volume base method (VBM) was used to construct the 3D model. The combination of deterministic and probabilistic methods was used to model the facies workflow process to capture the geometrics of depositional environmental element. The truncated Gaussian simulation method was used with vertical trends option to obtain vertical transitional lithofacies in most of the reservoirs. Verification of results and detailed discussion of the proposed workflow and methodology is based on comparison with the conventional method. The saturation height function (SHF) equation applied to the water saturation model and permeability model improved the 3-D properties modelling workflow. The pillar gridding process was identified as the stage that increases the timeframe in 3-D modelling workflow. The results have proven to improve the overall timeframe and maximize the value of the field studies. The proposed method can be applied to a broad and complex geologic area. And is useful for marginal field development, by contributing economically and improving the deliverability of the entire project.
Performance Evaluation of Cashew Nut Shell Liquid CNSL as Flow Improver for Waxy Crude Oils
Authors: Eke William Iheanyi , Achugasim Ozioma , Ofordile Samuel E. , Ajienka Joseph .A. , Akaranta Onyewuchi 
Published: July 2019

Abstract
Use of chemical additives for the control of wax formation and to improve flow properties of waxy crude oil is increasingly being adopted by oil industry operators. Most of these additives, such as pour point depressants, wax crystal modifiers or wax inhibitors are synthetic polymeric compounds, with poly acrylates and methacrylates, poly(alkylmaleate-co-α-olefin), poly(styrene-co-alkylmaleamide) and poly(ethylene-co-vinyl acetate) constituting the dominant chemistry. The high specificity of pour point depressant formulations to oil wells and the considerable expense incurred by industry operators on chemical injections continue to increase the interest for the development of better and cheaper chemical solutions to the wax formation problem. The present work reports the application of natural Cashew Nut Shell Liquid (CNSL) as a flow improver for waxy crude oils and its potential as a veritable resource for the development of new pour point depressants for waxy crude oils. CNSL was solvent-extracted from the shells of Cashew Nut (Anacardium Occidentale L.) using a soxhlet extractor. The physico-chemical properties of CNSL were determined. Functional group characterization was carried out by Fourier Transform Infrared Spectroscopy (FTIR). Rheological evaluation of CNSL at temperatures ranging from 10°C to 60°C using a coaxial cylinder rotational viscometer showed Newtonian behavior. Two Niger-Delta waxy crude oils were characterized to determine their API gravity, water content, kinematic and dynamic viscosity, pour point, Wax Appearance Temperature, wax content, asphaltene content and paraffin carbon number distribution. Wax formation in neat and CNSL-dosed crude oil was studied using cross-polarized microscopy. The pour point of a test crude oil dosed with CNSL at 4000ppm was depressed by 6°C. CNSL reduced the viscosity of the two waxy crude oils by 60% and 35% respectively during couette flow at a temperature of 10°C. CNSL can function as a pour point depressant and viscosity reducer for waxy crude oils and holds promise as a renewable chemical feedstock for the production of pour point depressants and other oilfield chemicals.
Effect of Temperature and Salt Concentration on Rheological Behaviour of Surfactin
Authors: Salihu S. M. , Abubakar A. J. , Meisam B. , Emmanuel U. A. , Hassan K. Y. , Aminu A. Y. 
Published: July 2019

Abstract
Behavioural changes of surfactants due to temperature fluctuations, and its interaction with saline environment, is very common during oil and gas operations. Exhibition of transient or permanent flow behaviour is one form of these changes. Therefore, effect of temperature and ionic concentrations (salinity) on flow behaviour of sodium surfactin was experimentally investigated. ORCADA® software-controlled OFITE viscometer (Model 1100) was used to conduct steady-shear study, at 23–50 °C temperature, 0.1–1.5 molar (M) salt concentrations and 0.025–1.0 % surfactin dosages. Sodium surfactin behaves as non-Newtonian fluid, with a pseudoplastic pattern exhibited in aqueous and 0.25-1.5M saline media. Effect of changes in temperature and salinity on apparent viscosity of surfactin was surfactant-dosage dependent. Furthermore, shear-thickening effect set in at a critical shear rate of 680.9 s-1, signifying flow-induced self-aggregation. Surfactant dosages 0.075 and to a lesser extent 0.1% were minimally affected by changes in temperatures, salinity and rate of shear not exceeding 680.9 s-1. The findings suggest pumpability and dispersion characteristics of the biosurfactant.
On the Characterisation of the Flow Regimes of Drilling Fluids
Authors: Ajayi Oluwaseun E. , Lawal Kazeem A. , Ukaonu Cyril E. , Alabi Tunde , Okoh Oluchukwu , Igbokwe Obianuju 
Published: July 2019

Abstract
Drilling fluids are vital elements in the safe, efficient and effective construction of wells. Their key functions include transporting drill cuttings to the surface, cooling and lubrication of drill string, cleaning build-up deposits on drill bits and tools, as well as stabilisation of the borehole and pressure control. Because they are often a complex mixture of different solids and fluids, the rheology of drilling fluids is usually complicated. As a result, they typically exhibit non-Newtonian flow behaviours. While the traditional practice is to use critical velocity to describe the flow regimes of drilling fluids by discriminating between laminar and turbulent conditions, this paper explores the applicability of Reynolds numlber (NRe), which is a more robust and universal dimensionless quantity to characterise flow regimes.
Models to estimate NRe of drilling fluids are explored for Bingham and power-law types of drilling fluids, including development of models for other non-Newtonian behaviours such as shear-thinning and shear-thickening. More important, the models provide a veritable basis to compare the hydraulic characteristics of a drilling-fluid mixture against its Newtonian counterparts under similar conditions. In addition, these models would facilitate the exploitation of the concept of dynamic similarity to improve the design and benchmarking of the flow characteristics of different drilling fluids in different systems and under diverse conditions. Examples are provided that show the robustness of using NRe as against critical velocity, to identify flow regimes of drilling fluids.
The applicability of the proposed models and ideas are not limited to drilling fluid hydraulics. The findings are relevant in other areas of transporting non-Newtonian fluids such as polymer for enhanced-oil recovery and multiphase mixtures such as emulsions, waxy crudes and general pipeline transport. Additionally, the principles and insights should be of interest to other industries such as food processing and chemical manufacturing.
The Future of Petroleum Engineering in an Emerging Renewable-Energy World
Authors: Lawan Zainab M. , Lawal Kazeem A. , Ukaonu Cyril E. , Eyitayo Stella I. , Matemilola Saka 
Published: July 2019

Abstract
The global energy demand is constantly rising due to urbanisation and population growth. Consequently, the petroleum industry has been ensuring affordable supply to match demand through exploitation and production of oil and gas. Nonetheless, there is increasing drive to shift towards renewables being an energy source that is ‘inexhaustible’, while decreasing the intensity of anthropogenic greenhouse gases as well as mitigating other negative environmental impacts of hydrocarbon field development. However, this shift is a threat to the upstream sector of the petroleum industry, specifically to petroleum engineering (PE), given its potential to lower hydrocarbon demand while raising carbon taxes of oil and gas companies.
Against this background, this paper takes a closer look at what lies ahead for PE in an emerging renewable energy (RE) world. It is shown that RE can be integrated into some conventional PE activities such as the use of solar energy for thermally enhanced-oil recovery and the application of its skillsets to advance the body of knowledge in geothermal engineering.
Despite RE's comparative advantages, it faces challenges in energy storage and intermittency of supply. The paper examines the influence of PE in some industries that depend on its products and relevant skill sets. It also explores the interplay between PE and other apparently remote industries is explored.
In conclusion, the future of PE is considered promising, though it needs to continuously re-invent itself. The reality is that it contributes not only to energy production, but many aspects of daily life. Compared to petroleum derivatives, the alternative products are yet to attain sufficient maturity for sustained large-scale utilisation. In principle, the breadth and depth of challenges that RE faces suggest that the world's dependence on PE is not likely to shift dramatically in the next couple of decades.
Gas Lift Optimization within Field Capacity Limitations
Authors: Ifeanyi Uche Chukwunonso , Esieboma Samuel , Uche Jennifer 
Published: July 2019

Abstract
Optimizing oil production with facility constraints has become a challenge to most E&P companies even as they pursue sustainable resources. The innovative gas lift technique overcomes this challenge. The conventional gas lift well system has long been in use, but the design most times is limited by gas availability and pressure which limits the depth of gas lift injection for improved production rates. This challenge may not be evident in matured producing fields with gas compressors installed with available non-associated gas source wells, but truly such challenges arise in new fields especially owned by indigenous companies where much uncertainties at an early field life unavoidably allows you to be more stringent in expenditures towards development of a field gas lift project. A new gas lift concept was developed and studied in Field A in an offshore field of the Niger delta in the absence of gas compressors. This design has been proven to be suitable because it was used to bring four closed wells online even when those wells were removed from the company annual forecast. The original design consists of a minimum of two unloading valves and an orifice at a deeper depth, but because of the absence of scrubbers and gas compressors in the facility, pressure depletion in the reservoirs caused four flowing wells to be closed. The new design then sets dummy at shallow mandrels and uses a modified size of orifice to optimize available pressure and gas required to open the closed wells and still sustain other gas lifted wells connected to the same gas lift manifold. This campaign resulted to an additional 7000Bopd which is the primary discussion of this paper.
Physicochemical Characterization of Starch from Unripe Artocarpus heterophyllus Lam Pulp as a Low-Cost Starch Source for Oilfield Applications
Authors: Adewumi C. N , Achugasim O , Ogali R. E , Akaranta O 
Published: July 2019

Abstract
Starches serve as vital raw materials in many industrial applications especially in food, textile, pharmaceutical and petroleum industries. In petroleum industry, chemically modified starches are used in water based drilling mud to enhance fluid loss and viscosity in the formation during drilling. Most starches used for these applications are obtained from food sources such as corn, potato and cassava and this affects the overall production cost. Artocarpus heterophyllus Lam (AHL) is a tropical tree with large bulb (fruit) containing pulp and seed. In Nigeria, this tree grows in the wild or homes but its fruit is not seen as a food source and thus allowed to waste. Starch was extracted from the pulp of unripe but matured AHL using wet milling method, and the extracted starch was examined for its proximate composition and physicochemical properties. Starch extraction from the unripe pulp gave a starch yield of 44.12±1.13% and the physicochemical characterization shows that the starch has high amylose content (24.09±0.11%), water absorption capacity (116±0.18%), gelatinization temperature (71°C) and the swelling power increases with increase in temperature. The thermal behavior of the starch studied with differential scanning calorimeter (DSC) demonstrated a distinguished endothermic peak with distinct onset, peak and conclusion temperatures. The scanning electron microscope (SEM) result showed that the starch granules are small sized and aggregate together with high tendency of forming network of granules. The results obtained from the physicochemical characterization of unripe AHL pulp starch shows that it has high potential for oilfield applications.
Complex Reservoir Re-Development in a Deep Offshore Maturing Field: Akpo Field Case Study
Authors: Adeyemi Adeoye , Uwerikowe Gabriel , Tyagi Tapesh , Oukmal Jed , Usman Musa 
Published: July 2019

Abstract
With increasing complexity of reservoir developments, there is often a marked deviation from the field development plan (FDP), thus, requiring complementary developments with infill wells. This paper addresses this necessity whilst using the Akpo field reservoir B as a case study. Our case is an oil-bearing, highly faulted turbidite channel-levees system. The reservoir comprises three different units (Upper, Middle and Lower) with gross interval of about 140 m and good porosity and permeability values. The hydrocarbon-water contact (HWC) varies across fault blocks with little certainty about reservoir connectivity. It was assumed in the initial FDP that two producers located around the top structure would be supported by two injector wells located on the flanks near the HWC. In 2011, the first producer (Akpo-XP) was completed in the three units and equipped with an inflow control valve (ICV). From fluid samples collected and the selective acquisition of dynamic data from these intervals, results showed that the Upper unit was disconnected from the Middle and Lower units. Consequently, Akpo-XP was forced to produce only from the Middle and Lower units in order to be supported by a northern injector (Akpo-YW) in the same interval. To complete the initial development, another pair of wells (producer-injector) was drilled and completed in the upper unit. All wells were equipped with down-hole pressure gauges for connectivity assessment.
In 2015, a seismic monitor was acquired, processed and interpreted whilst integrating production, injection and pressure data. The 4D seismic data confirmed specific fluid movements in the reservoir and a reservoir re-development could be sanctioned with two infill wells (one producer and one injector) with estimated increase in up to 16 Mboe of reserves and incremental production of 13 kbopd.
A post-mortem analysis of these two infill wells showed a combined incremental production slightly above expectations.
Formulation of Bio-Waste Derived Polymer and Its Application in Enhanced Oil Recovery
Authors: Fadairo Adesina , Adeyemi Gbadegesin , Onyema Obioma , Adesina Adedapo 
Published: July 2019

Abstract
Polymers are substances considered to have their molecular structure being built up majorly from a large amount of similar smaller units bonded together, for instance synthetic organic materials used as plastics and resins. It has been stated that due to reservoir heterogeneity and capillary forces affecting the water flood process causing low oil recovery after a particular interim, the technique of implementing polymer flooding as a chemical flooding mechanism has been introduced and is rapidly gaining attention in the oil and gas industry. The study describes primarily the formulation of a specific bio-polymer product and examining its performance in Enhanced oil recovery. The musa paradisiaca derived bio-polymer solution was formulated and injected at different concentrations by performing simultaneous experiments at certain operating conditions using a reservoir permeability testing equipment (RPT). Core sample flooding experiment was performed on three core samples of varying porosity and permeability. The bio-polymer is flooded through core sample at different pore volumes using the RPT as the flooding equipment. The bio-polymer solution has the ability to lower mobility by reducing the relative permeability to water as well as increasing its viscosity (an index of mobility ratio improvement), which reduces the mobility of the driving phase, hence causing an increased mobility of the driven phase(oil). From the experimental procedure performed in this study, the results indicate that the injection of newly derived bio-polymer solution into oil strata enhanced oil recovery where the incremental oil recovery attained for each core sample were 16.71%, 25.58% and 14.55% of the respective original oil in place (OOIP), indicating an average incremental oil recovery of about 18.94% for entire experiment performed. The results obtained from the flooding of newly derived bio-polymer solution proved a better performance in oil recovery percentage when compared with flooding of gum arabic polymer solution.
Estimation of Reservoir Permeability Using Analogue Core Data for Green Field: Case Studies from Niger Delta
Authors: Das Anindya , Anijekwu Chinedu , Maguire Kelly , Wood Mark , Akinrolabu Segun , Adenaiye Olaniyi , Iyowu Olakunle , Duvbiama Omolara , Ozoemene Uche , Amrasa Kefe 
Published: July 2019

Abstract
Permeability is one of the most important parameters of reservoir rocks; it defines the capacity of rocks to transmit fluids in pore spaces. Permeability prediction is of extreme importance in deciding the field development strategy for green reservoirs. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. Generally, the sources of permeability measurements in green field are from core data, well test data and Nuclear Magnetic Resonance (NMR) data. However, core information, well test information and NMR information are usually very limited due to high cost of acquisition making justification usually difficult. The consequence is that we have very low ratio of cored to the total reservoirs in the Niger Delta.
This paper discusses a methodology for accurately estimating permeability using analogue fields/reservoirs core data in green reservoirs. The main factors to consider in choosing a suitable analogue includes Facies classification, relative depth of the reservoirs, average porosity and histogram of the Gamma ray values between the subject and analogue reservoirs. This selection is usually an integrated effort between the teams Geologist and Petrophysicist.
In this study, two fields were selected where permeability prediction was based on analogue core data.
A robust Niger delta wide analogue selection process was applied first to identify the analogue field where core data exists. After selection of the analogue field, facies-wise poroperm transform was built. This poroperm transforms were then validated in one of the fields where real core measurements were available post study. This blind test with real core permeability data indicated an excellent match with analogue based permeability model. In the other field, the analogue based permeability was validated against NMR and mobility data acquired in some of the reservoirs.
This workflow establishes the robustness of using existing analogue data to reduce the subsurface uncertainty and justify an integrated workflow of estimating permeability in the green field rather than acquiring a new data to support development decision.
Efficient Placement of Relief Well Using Combination of Tools
Authors: Pedro Abiye Iyalla , Feltracco Davide , Pasquale Antonio , Gravante Elpidio 
Published: July 2019

Abstract
A Well with plug set in both tubing was sabotaged and even after initially capping the well, it was observed that attempting to kill the Target Well via surface pumping was abortive.
Therefore, in order to achieve well control, drilling a relief well became imperative and required some critical decision to be taken. This include location selection, type fluid to be used in drilling, the casing setting depth, downhole measuring tools for use, as well as contractors needed in achieving success in a suitation of incomplete well survey data.
This paper presents how this keys needs were met in drilling the Relief Well planned for 97days trouble free and performed in 107days from spud to hitting Target Well. The success was on single attempt in spite of it having an incomplete survey record acquired 49 years earlier.