bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reducing Reservoir Uncertainty through Systematic Data Integration and Analysis: Case Study of a Partially Appraised Gas Field
Authors: Obi Azubike , Inaingo Osuagwu , Olakunle Iyowu , Uche Ozoemene , Anyaehie James , Muyiwa Esho 
Published: August 2015

Abstract
The maturation and development of hydrocarbons in partially appraised fields (PAFs) is often threatened by the high degree of subsurface uncertainty resulting from limited well penetration and paucity of subsurface data in such fields. The uncertainties ranges are sometimes very wide and the resultant cost of further appraisal is so prohibitive that the value and economic indices of carrying out development projects in these fields are severely eroded. For PAFs which are gas-bearing, the challenge is further underscored by the relatively lower price of natural gas and associated higher cost of infrastructure compared to oil. Thus, if not adequately managed, the subsurface uncertainties can go a long way in defining the economic success or failure of planned development projects in PAFs. For this reason, geoscientists and petroleum engineers are tasked with the responsibility of integrating and analysing all available data in the field with the aim of assessing, managing and reducing these uncertainty ranges as much as possible.
The OZ field, which is discussed in this paper, is located in the Niger Delta and has a maximum of 6 well penetrations across sixteen (16) reservoirs in a predominantly gas field. Comprehensive data acquisition (electrical surveys and formation pressures and samples) from the last well drilled in the field in 2012, helped eliminate the fluid typing and contact uncertainties in most of the reservoirs.
However, for the potentially largest reservoir in the field, the actual fluid contacts (Gas Oil Contact or Hydrocarbon Water Contact) were not logged rather a Gas-Down-To (GDT) and Water-Up-To (WUT) were logged in this reservoir at 100ft apart. With a 100ft column of undifferentiated fluid, the resource volumetric uncertainties varied substantially and if the entire 100 ft column contained hydrocarbon then depending on the type (gas or oil) and ratio, the planned development of the reservoir could easily change from primarily gas to an oil development with a gas-cap blowdown in the future. Hence, the fluid typing and contact delineation emerged as one of the major uncertainties associated with the development of the reservoir and the field at large. To reduce this uncertainty, systematic field reservoir pressure analysis coupled with the integration of other electrical surveys and regional knowledge were applied to significantly minimize the fluid type and contact uncertainties.
This paper showcases details of the analysis and its implication in cost reduction and project value enhancement.
Integrated Performance Based Gas Initially In-Place Estimates Update - An Aid To Optimum Natural Gas Field Development
Authors: Ikwan Ukauku , Ehighebolo Thaddeus , Bhattacharya Tirthankar , Das Debasis , Dongen Van , Madiba Gislain , Temitope Jegede , Ernest Ikpolo , Anaevune Austin , Sarkar Sudipto , Fouzdar Amit , Sanwoolu Fola , Esimaje Jolomi 
Published: August 2015

Abstract
Two methods exist for the estimation of Gas Initially In-Place – volumetrics (probabilistic or deterministic) and performance (material balance equation or numerical simulation). The more appropriate method will depend on the maturity of the project reservoir. For potential accumulations with limited information, the GIIP estimate may be volumetric-based using probabilistic methods, covering the range of possible outcomes with P90, P50 and P10 outcomes as low, best and high estimates. For fields where more subsurface data are available, the preferred method will generally shift towards volumetric-based GIIP estimates using deterministic low, best and high cases. Once a field is in production and sufficient data are available, a performance-based GIIP estimate should be established, including the appropriate range of uncertainty.
Over the years, the tendency has been to over-rely on volumetric-based estimates with little attention paid to performance based GIIP update leading to sub-optimal gas field development.
In this paper, we took a case-study reservoir having or tending towards negative reserves in course of its production life to underscore the need for timely update of GIIP based on performance data as an aid to optimal development of a gas field. Reservoir A has volumetrically based GIIP of 1.6 Tscf respectively leading to prediction of early End of Life (EOL) or negative reserves. When compared with performance based GIIP and updated volumetric GIIP of 2.04 Tscf to match performance data, the issue of early EOL or negative reserves was ameliorated and ultimate recoveries were optimized.
Performance based GIIP estimate is reliable when premised on appropriate choice of methods (P/Z material balance for depletion reservoirs, aquifer influx model in water drive gas reservoirs material balance model or dynamic simulation) integrating all available data as illustrated in the case studies.
To allow comparison between volumetric-based (static) and performance-based (dynamic) GIIP estimates and to understand the potential difference between the two, it is recommended that a current volumetric GIIP estimate should be maintained throughout the life of the field in addition to an up-to-date performance-based GIIP estimate to aid optimal gas field development.
Interference Test Pressures of a Reservoir with Vertical and Horizontal Wells
Authors: Giegbefumwen P. U. , Adewole E. S 
Published: August 2015

Abstract
Over the years, interference test analysis has become a veritable analytical tool in reservoir characterization of most brown fields. At interference the area between the wells has been adequately swept. Therefore, results obtained from interference data analysis show a better reservoir representation as compared to that obtained from single well test. This study presents an analysis of interference test data of horizontal and vertical wells for various well spacing using Malekzadeh's model. Malekzadeh assumed an isotropic reservoir condition. For the fact that anisotropy has a major effect on the pressure transient responses of horizontal well, the results of Malekzadeh have limited applicability. Thus, in an attempt to alleviate this limitation, this analytical study was borne.
The reservoir model used in this study is assumed to be anisotropic, laterally infinite and bounded at its top and bottom. Skin and wellbore storage effects are not considered. For proper analysis, three cases are considered: (1) an observation horizontal well and active vertical well, (2) observation vertical well and (3) active horizontal well and an active observation vertical well and an active horizontal well. Type curves are generated for each case.
Our results show a slope of 1.1513/cycle for Cases 1 and 2 and a slope of 2.303/cycle for Case 3 at interference for late time flow regime. However, a check on the effect of anisotropy reveals that directional permeabilities bring about a slightly higher bottomhole responses for late-time flow regimes. For pressure to be felt by adjacent wells, an enomous time is sometime needed pending on the location of the observation well.
In conclusion, our findings show that anisotropy strongly affects interfering pressures between wells.
An Analytical Model of Foam Resistance Factor in Gas Foam Flooding
Authors: Zang Jiali , Li Xiangfang , Chen Zhiming , Huang Liang , Li Yanzun , Telphi Yanick 
Published: August 2015

Abstract
Gas foam flooding is an effective technique to improve recovery and it has been successfully applied in some low permeability oil reservoirs. Among all parameters, foam resistance factor is regarded as an important index to evaluate the gas shutoff and water shutoff capacity of foam system. Until now, Foam Resistance Factor is normally obtained through solving the nonlinear regression equation based on laboratory foam flow experiment. The empirical formulas obtained through this method have low accuracy, limited application range and no repeatability.
In this study, we used the fractional flow theory to analyse the liquid and gas distribution and established a formula of solving water saturation in function of gas liquid ratio, connate water saturation and flowing gas fraction when foam flow is at steady-state. Then foam resistance factor prediction model was approached in absence of oil based on empirical and population-balance foam models which were employed to modify gas relative permeability and gas viscosity. Analytical method was proposed to estimate critical parameters, such as fmmob, Xf and FM, for model solution. A case was designed for illustrating detailed solution procedure. In the end, comparison between calculation FM data and simulation FM data were performed indicating a relatively good match.
Effective Hydrate Management during Gas Expansion
Authors: Olabisi Odutola Toyin , Sunday Ikiensikimama Sunday , Joseph Ajienka Atubokiki 
Published: August 2015

Abstract
As the world increases its natural gas development and exploitation projects, Gas hydrate will constitute a major flow assurance concern in most gas facilities. It is imperative to critically examine the various means of hydrate formation and effective ways of managing gas hydrates. This work considers gas hydrate formation due to gas expansion. It was discovered that hydrate formation may occur at the Joule Thompson's valve due to cooling during gas expansion. Hydrate prevention was effected by determining the critical point at which the expanded gas moves from the hydrate free zone to the hydrate risk zone. A comparative study was carried out to evaluate the effectiveness of methanol (MeOH) and monoethylene glycol (MEG) in hydrate inhibition during gas expansion. Hydrate formation curve and inhibitor performance curves were generated using CSMGem Software. MeOH performed better than MEG as 10wt% MeOH could prevent hydrate formation when the gas was expanded to about 3338 psia whereas, 10wt% of MEG could not prevent hydrate formation when gas was expanded beyond 3750 psia. This work will aid the engineer to assess problem areas upfront and to determine mitigating measures.
Material Balance Modeling and Performance Prediction of a Multi-Tank Reservoir
Authors: Idogun Iroro , Jeboda Olatunji , Charles Dawari , Ufomadu Happiness 
Published: August 2015

Abstract
Recent reservoir studies have shown great strides in capturing complex multi-tank reservoir systems using Material balance (MBAL®) model especially when these tanks are hydraulically connected. The preference of a simple and quick material balance method over numerical simulation is justified when time and budget constraints may hamper full field simulation modelling. The subject reservoir for this study is a mature hydraulically connected tank under waterflood. This paper compares reserves estimation using predictive material balance and dynamic simulation after history matching both models.
Results from this paper shows that for multi-tank modeling using of hydraulically connected reservoirs using MBAL, transmissibility modeling & aquifer modelling are key factors in achieving reasonably reliable MBAL models. A good understanding of the reservoir fault frame work and connectivity, adequate & reliable BHP, injection and production data are very important for attaining a good history match & model calibration. Results of this study show a good comparison between the Reserves estimate from both MBAL and that from dynamic simulation. Under the appropriate conditions, Predictive Material Balance is a quick alternative tool to reservoir simulation in reservoir performance prediction especially when time & resources are limited. Also, predictive material balance analysis should be applied in reservoir where the existing wells have adequate data to build reliable inflow & out flow models.
An Investment Matrix Model for Marginal Field Operators in Nigeria
Authors: Ashore Utomako , Onaiwu Oduwa , Olafuyi Olalekan , Sunmonu Rasak 
Published: August 2015

Abstract
In a bid to promote the participation of indigenous oil and gas companies in the upstream sector, the Nigerian government introduced the marginal field program which is aimed at encouraging local participation in the industry and to increase Nigeria's oil production.
The development of these fields has been quite challenging as petroleum projects require huge funds that are associated with a series of risks and uncertainties which a combination of experience, knowledge and careful evaluations may not be able to overcome.
Economic analysis is an integral part of every field development as it is the pivot on which several other decisions revolve. It helps to reduce the challenges by carrying out economic evaluations to find out the best petroleum investment opportunities in terms of cost, revenue and risk mitigation.
With the uncertainties in the oil and gas industry and in light of the current decline in the world oil price which has been having a negative impact on the Nigerian economy owing to the fact that 85% of Nigeria's revenue is gotten from the sale of crude oil, this study seeks to develop an investment matrix model for marginal fields in Nigeria. It recognizes the current drop in world oil price, analyzes its effects on marginal fields and proffers solutions on how marginal fields can stay afloat even with the current drop in oil price. Forecasts are carried out in case of a future drop in oil price and the results are incorporated into a deterministic model with the economic yardsticks as guiding factors in order to make the best economic decisions.
Steam-alternating-CO2 for heavy-oil recovery
Authors: Lawal Kazeem A , Tendo Fidelis 
Published: August 2015

Abstract
The commercial exploitation of relatively deep heavy-oil reservoirs is often accomplished by injecting only high-quality steam (steam-alone). This practice is associated with prohibitive CO2 emissions. However, tightening constraints on fuel, water, and the environment are inspiring enhancements to the traditional steam-alone recovery methods. As an improvement, this paper introduces and evaluates the steam-alternating-CO2 (SAC) process for developing these resources.
Conceptually, SAC entails injecting steam and CO2 in cycles while oil is produced continuously. Essentially, hot CO2 partially replaces steam as an injectant. Where steam and CO2 are available, another possible enhancement option is the simultaneous steam-CO2 (SSC) process, involving the co-injection of steam and CO2 as a mixture, rather than in cycles. Compared to the steam-alone process, SAC and SSC promise better project performance, largely due to enhanced thermal efficiency and underground carbon sequestration.
Some conceptual thoughts behind SAC are explored, including how the required CO2 injectant would be sourced from the flue-gas emitted during steam generation. It is shown that the overall process is potentially self-sustaining, as the required CO2 is generated and utilised within the same closed system, thus minimising fugitive emissions. Relevant process-engineering aspects are highlighted.
As a case-study, 3-D multi-phase/multi-component thermal-reservoir simulations are conducted using a representative sector of the Nigerian heavy-oil deposit. Performances of the SAC and SSC processes are compared, while using the steam-alone process as the reference case. In terms of oil-recovery and thermal efficiencies, simulation results suggest that SAC is superior to SSC.
Although SAC yields a lower oil-recovery compared to its steam-alone counterpart, the former has higher thermal and environmental efficiencies, as it returns better oil-recovery per unit steam-consumption. Differences in their recovery performances are explained. Based on these results, SAC is considered a promising thermal-recovery method. Thus, for sustainable energy-supply, the proposed in-situ extraction method deserves attention.
Application of Interconnected Fibre-Network to Improve Sand-Control in Water Injectors: Preliminary Insights From Field Data
Authors: Lawal Kazeem A. , Okosun Joshua , Olatunji Idris , Okonkwo Paulinus , Horsfall Ipalibo , Adenuga Ademola , Ogunsina Oluseye , Ekebafe Abraham , Mbanefo Edith , Tendo Fidelis , Pokima Sophie , Bapoo Saeed 
Published: August 2015

Abstract
To minimise well-count, sustain high injectivity and enable high offtake rates from the associated oil producers, cased-hole frac-pack water injectors in deepwater fields are often operated at relatively high injection rates. However, continuous injection at high rates (velocities) may displace the proppants in the sand-control system, increasing the vulnerability of such injectors to impairments by fines invasion. To mitigate this impairment mechanism, a new fibre-based product (interconnected fibre network) was recently introduced for locking proppants in-place. Although the product was extensively tested in the laboratory prior to its release, its field performance and impacts on injectivity remain uncertain.
To improve the reliability and longevity of a critical frac-pack water-injection well in a giant West-Africa deepwater oilfield, this proprietary product was recently deployed. Being the first field application in the exploration-and-production industry, this case-study presents an opportunity to validate the results of prior numerical and laboratory experiments while identifying relevant improvement areas for future developments and field applications. Specifically, the impacts of this product on well injectivity and other performance indicators were investigated.
Within 6 months of start-up, the well injected ca. 7 MMbbl of treated seawater and surveillance data acquired. Although this fibre-reinforced cased-hole frac-pack injector is still at relative infancy, this paper presents initial insights gained from managing the well. For the current evaluation, the surveillance techniques employed include the Hall-plot and deep-bed filtration analysis, complemented by step-rate, injectivity and pressure-transient tests. Among other findings, the performance of this well is generally comparable to the conventional (unreinforced) frac-pack injectors completed in an analogue reservoir in the same field.
To a reasonable extent, this pioneering case-study allays the pre-installation concerns that the product would hamper injectivity. The present observations notwithstanding, there remain some key uncertainties and challenges, which are potentially reducible as more statistically significant performance datasets become available from this field and elsewhere. It is too early to conclude from available data that the fibre-reinforced frac-pack performs better than the (previously used) non-fibre-reinforced frac pack injectors in this field.
A Review of Produced Water Management Processes: A Case Study of a Brown Field in Niger Delta
Authors: Ofili O. , Temisanren T. , Olafuyi O. 
Published: August 2015

Abstract
Produced water often contains chemicals, oil and sometimes naturally occurring radioactive materials which could be harmful to the environment. Its management is aimed at reducing the toxicity of discharged volumes and mitigates the effects in the environment.
This study evaluated the management method being carried out, the physio-chemical properties and trace metals constituents of produced water from a well in the Niger-Delta to determine the extent of compliance with standards of discharge.
The results obtained showed that the pH values, Zinc, copper and cadmium were within acceptable regulatory limits for near-shore and inland discharge; the concentration of trace metals like iron, lead, chromium were not within acceptable limits for near-shore and inland discharge. The constituent of the produced water of most importance was the concentration of the dispersed oil in the water and the management method which is being used reduces the oil concentration to a minimum of 250mg/l before disposal which does not comply with the regulatory standard of 10mg/l for inland disposal.
A better management method was proposed which reduces the oil concentration to 50-75mg/l based on the relationship between oil droplet size and oil concentration and the economics of operation. Also, due to the oil and water production rates, it was proposed that some of the produced water be used for waterflooding to obtain additional recoverable reserves thereby optimizing the water management approach.
Surfactant-Polymer Flooding Schemes (A Comparative Analysis)
Authors: Felix Uwari , Ayodele Taiwo Oluwaseun , Olalekan Olafuyi 
Published: August 2015

Abstract
Surfactant Polymer (SP) flooding-a chemical EOR method, involves the injection of surfactants into the reservoir to reduce interfacial tension between oil and water and thus reduce capillary pressure for easy mobilization of oil. Polymers are also injected alongside to reduce mobility ratio and gather the oil droplet within the reservoir to create an oil bank and mobilize the oil towards the wellbore.
In this paper, three different methods or mechanisms of implementing surfactant Polymer flooding were considered. Firstly, for Scheme or Method A, after water flooding, Sodium Dodecyl sulphate slug was injected then followed by gum Arabic slug. For Scheme B, a slug consisting of a mixture of Sodium Dodecyl sulphate and gum Arabic was injected after water flooding. In Scheme C, the core was first soaked with Sodium Dodecyl sulphate and then flooded with gum Arabic.
The result showed a recovery of 56.25% of the water flooding residual oil for the first method while the other two Methods yielded displacement efficiencies of 66.12% and 64.4% respectively.
In summary, the Mechanisms of implementing an SP flooding have some effects on the Oil recovery and as such care must be taken in selecting the mechanism to be adopted so as to optimize recovery.
Ranking of C6+ Composition Split Schemes of Pipeline Gas for Hydrocarbon Dewpoint Determination
Authors: Aniefiok Livinus 
Published: August 2015

Abstract
For energy calculation and hydrocarbon dewpoint calculation of pipeline gas, many gas processors and end-users are now applying equation of state, either a Peng-Robinson (PR) or Soave-Redlich-Kwong (SRK) equation of state, to the pipeline gas composition after splitting the C6+ component into a fixed ratio of n-hexane, n-heptane and n-octane: varying predictions are obtained because the commonly used percentage C6+ composition splits published in GPA standard are based on empirical studies of most pipeline gases. In addition, several different software packages are available to the industry to perform dew point calculations, and each of these may yield different predictions using the same gas compositions and equations of state.
This work therefore presents the ranking of the common C6+ split schemes for hydrocarbon dewpoint determination on the basis of C6+ mole fraction through the study of several common C6+ composition splits of pipeline gas applied to a large set of field and hypothetical C6+ data by means of HYSYS(with PR EOS and SRK EOS for predicting hydrocarbon dewpoint.