bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modified Solvent-Based Mud Acid Stimulation of Condensate Gas Reservoirs: Case Study of UUU Cluster in West Niger Delta
Authors: Osode Peter , Soro Augustine , Iyama Andy , Otiede David , Olawunmi Oduyemi , Nwadiogbu Lawrence 
Published: July 2023

Abstract
Matrix acid stimulation has been successfully applied to remove formation damage in the high-permeability Niger Delta sandstone oil and gas reservoirs since the mid-eighties. The predominant acid treatment fluid of choice is expectedly the regular mud acid (RMA) – hydrochloric acid and hydrofluoric acid (HCl:HF combination acid). Fluid formulation is however challenging for gas wells due condensate banking and water block development in the near-wellbore area at pressures below dew point pressure.
Candidate wells were identified for stimulation after well test data analysis and production performance evaluation. This paper focuses on selection and application of a modified solvent-based RMA to remove drilling and completion fluid-induced formation damage in addition to production-related damage in high-rate, gas-condensate wells in a cluster of western Niger Delta fields.
A low-strength alcoholic mud acid was selected primarily based on bottomhole temperature (&lt; 220 °F), formation mineralogy – over 70% quartz with low clay content (&lt; 5%) for the high-permeability hydrocarbon formations. The alcohol-based solvent – methanol was included in all stage treatment fluids (preflush, main treatment and overflush) for condensate bank removal and improved well production performance. Treatment fluid injection and soak treatment was applied at minimum threshold of 100 gallons per foot across the perforations using coil tubing.
The results indicated improved well-inflow performance for the old gas-condensate compared to the newly completed well after adequate clean up. Average production gain realised in the aged wells was over 50%. This paper has confirmed the applicability of this modified RMA for near-wellbore formation damage removal without increasing the producing water gas ratio (WGR) in gas wells.
Darcy-Forchheimer's Model: Application in Hydraulic Fracturing Design and Optimisation.
Authors: Hart A. F. , Omobolanle O. C. 
Published: July 2023

Abstract
Hydraulic fracturing is a proven stimulation technique for enhancing production and maximizing recovery from tight and unconventional reservoirs. The treatment improves the effective conductivity, enhances production and economic recovery of the reserves. This paper investigates the impact of in-situ closure pressure and bottom-hole temperature on the effective permeability of proppant-pack and inertial flow coefficient. Core samples from a sandstone formation were analyzed in this experiment; the samples were subjected to closure pressures between 1,000–10,000psi at 100°F–200°F. The corresponding proppant-pack permeabilities were measured across the core while the inertia flow co-efficient values were calculated with the Darcy-Forchheimer's model. The results show that the effective proppant-pack permeability reduces with increasing in-situ closure pressure and inertial flow coefficient.
Remedial Sand Control Using Chemical Sand Consolidation, A Field Experience
Authors: Stephen Babagbemi Adetoye , Mofunlewi Samuel , Williams Chad 
Published: July 2023

Abstract
Weak and loose sand grains that make up oil and gas formation matrix can be strengthened by chemical bonding while still maintaining the desired permeability for optimum production. This case study involves a well with high sand production rate that led to surface equipment failure and eventual shut down of an entire flow station for months. This paper discusses the application and results of the deployment of a chemical sand consolidation fluid system on the candidate well. The process involves mixing and squeezing the system into the formation and allow it to set. Once cured, the system forms an artificial core with a high compressive strength and permeability thereby preventing the well from producing sand. The system is externally catalyzed with two major additives in the mix that work in synergy to enhance wettability of the formation materials and to increase unconfined compressive strength of unconsolidated sand. In selecting a candidate well, formation data including bottom hole temperature and pressure, interval length, permeability, porosity and mineralogy were carefully studied and analyzed to build a geo-mechanical model that predicts minimum unconfined compressive strength (UCS) for sand sand-free production. Laboratory model and sanding assessment were carried out by developing cores using actual well formation materials. The fluid system was prepared and flown through cylindrical cores in the laboratory under reservoir conditions. Actual field deployment was carried out using coiled tubing. The well was shut-in for 24hrs after treatment and opened up for sand free production. Post treatment analysis of the surface cores made during deployment yielded a UCS of 789Psi and permeability to brine that stabilized at 1963mD.
Offline Production Tree Installation: Key Decisions, Value Drivers and Lessons Learnt
Authors: Elendu C. , Bajomo V. M. , Enuneku N. , Nwamara N. J. 
Published: July 2023

Abstract
After successfully drilling and completing 40 wells with 5000 psi rated production trees in the swamp operation within a 5-year campaign the diverter deck on the Swamp Rig barge never posed a challenge until 6650 psi production tree had to be installed on two non-associated gas wells. The Field Development Plan (FDP) was approved in 2013 and it contained a 2-well (NAG-1A and NAG-2A) development plan for the target reservoirs with estimated recovery of 213 BCF of rich gas and 4.6 MMSTB of pool condensate at initial production rates of 35 MMSCFD and 1,380 BCPD each for both wells.
Gas production from these wells will bulk flow to the NAG separator located at the Production Flow Station where the pool condensate will be separated from it. The rich gas will subsequently be transported to the gas plant onshore bypass for supply to the domestic market through the ELPS.
NAG-1A and NAG-2A wells are part of the Non-Associated Gas (NAG) development and were completed as single string deviated gas producers with HRWP completions to meet target production rates and reserve recovery.
After successfully drilling and completing the NAG-1A well, it was later discovered that the diverter deck of the rig was going to impact the 6650 psi production tree while moving the rig onto the NAG-2A well slot on the same jacket.
This paper sets out to give an overview of the planning, risks assessment and execution for using a crane barge to successfully install two 6650 psi production trees on two NAG wells incidents free, after the drilling rig departed location due to the diverter deck limitation. Lessons learned and best practices were captured as well as the resultant cost savings from using the crane barge instead of the rig to install the production trees on the two NAG wells.
The total number of days to complete the offline XMT installation using a crane barge was 5 days for both wells while working daylight hours only. This resulted in a cost savings of 154,200 USD per well.
A Production-Allocation Method for Two-Zone Downhole Commingling in Semi-Intelligent Oil Wells
Authors: Olabimtan D. , Lawal K. A. , Owolabi S. , Mumuni O. T. , Omion O. O. , Jimkuta M. , Dimari A. M. , Okeke H. C. , Obinna-Ewuzie U. , Mmata B. , Onyekonwu M. 
Published: July 2023

Abstract
Downhole commingling is a production-optimization method for producing multiple reservoirs (zones) via a single wellbore. It offers cheap exploitation of small reservoirs that would have remained stranded for uneconomic offtake rates and recovery. Although this method reduces development costs and environmental footprints, production allocation is a concern, especially in the absence of intelligent completion. Here, an intelligent commingling employs active inflow control valves (ICV) across individual zones. Nevertheless, this ideal scenario of full intelligence is not always available in practice. Considering the opportunities and challenges of stranded hydrocarbon resources amid tightening global energy supply and drive for cleaner fuel, this paper considers semi-intelligent commingled production (SICP) as an enabler for production acceleration. An SICP has a permanent downhole gauge for real-time pressure and temperature measurements but, unlike its intelligent counterpart, SICP lacks ICVs for zonal surveillance and control. We develop a fit-for-purpose method and workflow for back-allocation in a two-zone SICP. It is a semi-empirical approach premised on pressure-volume-temperature (PVT) characterization. Different mixing proportions of fluid samples from target contributing zones are baselined in terms of compositions and aggregate properties. These same properties of commingled stream are monitored over time to back-allocate produced gas, oil and water phases. Unlike production logging and conventional fingerprinting that require frequent well re-entry and large spectrum of fluid components respectively, our method is cheap and minimizes well re-entry and its associated risks. Specifically, we exploit C1, C7+, and salinity (Cl−) as markers to uniquely characterize the gas, oil and water phases of individual zones, respectively. Given the challenges posed by highly biodegraded oil reservoirs and reservoirs with similar PVT properties, we propose augmenting our back-allocation method with the use of biomarkers from saturate and aromatic fractions of the oil in such cases.
Effects of Carbon Dioxide and Liquified Petroleum Gas Mixture on Minimum Miscibility Pressure for Carbon Dioxide Storage and Enhanced Oil Recovery
Authors: Al_Ani M. , Sidek M. A. , Jaafar M. Z. , Agi A. , Gbonhinbor J. , Ridzuan N. , Mahat S. Q. A. , Yakassai F. , Ngouangna E. , Oseh J. 
Published: July 2023

Abstract
The increase in carbon dioxide (CO2) and other greenhouse gases emission into the atmosphere has resulted in global warming and climate change. CO2 capture and storage are viable option to mitigate against this problem. Hence, in this study the potential of CO2 storage in the Malay Basin for enhanced oil recovery (EOR) was evaluated using Eclipse. Likewise, the effect of the synergy between CO2 ratio and liquefied petroleum gas (LPG) mixture on optimum miscible pressure (MMP) for CO2 storage and CO2-EOR process was investigated. The results indicate that 137 MMSCF of CO2 can be stored through this process. Consequently, the total amount of oil production was within range of 190 MMSTB to 230 MMSTB. Besides, the volume of oil production through the process of CO2-EOR increased with increase in injection of CO2. Injection of CO2 and LPG mixture show that MMP decreased from 1,910 psi to 1,700 psi. Therefore, it can be concluded from this study that CO2-EOR process followed the multiple contact miscibility scheme whereby the residual oil was swept towards the producing wells.
Effect of Temperature and Particle Exposure on Hydroxyapatite Nanoparticles on Wettability Alteration of Oil-Wet Sandstone
Authors: Ngouangna E. , Jaafar M. Z. , Anam M. N. , Agi A. , Gbonhinbor J. , Ridzuan N. , Mahat S. Q. A. , Yakassai F. , Oseh J. , Al_Ani M. 
Published: July 2023

Abstract
Nanofluid treatment is being developed to improve oil recovery and reduce residual oil entrapment in sandstone reservoirs. Nanoparticles for enhanced oil recovery (EOR) at ambient conditions have shown good potential in recent research. The efficiency on EOR has been found to be significantly influenced by nanofluid composition, exposure and time. However, there is a serious lack of knowledge regarding the influence of temperature on nanofluid performance. The effects of temperature, exposure, time, and particle size of hydroxyapatite nanoparticles (HAP) on the wettability alteration of an oil-wet sandstone were thoroughly investigated, and the stability of the nanofluids was equally examined. At higher temperatures, it was discovered that nanofluid treatment is more effective, with nanoparticle size having little or no influence. The sandstone surface mechanically absorbed most nanoparticles in an irreversible manner. The HAP nanofluid was still effective at high temperature reservoir condition and is herein proposed.
Techniques for Investment Decision Making for Oil and Gas Assets
Authors: Obidike Peter , Nwosi-Anele Adaobi 
Published: July 2023

Abstract
Oil and gas will remain a critical source of energy in the global energy mix and will continue to command attention in investment decisions given resource rich countrie's dependence on hydrocarbon for revenue, even with the energy transition.
The techniques for investment decision making vary, depending on the drivers of the decisions. Techniques for investment decision making can be both quantitative and qualitative. Most techniques will start with quantitative analysis but ultimately end up depending on qualitative views from project teams and top management decision makers as they consider factors beyond quantitative evaluations such as political and strategic views.
Quantitative evaluations involve the use of economic indicators, stochastic evaluation, and prevailing market conditions for the assessment of profitability of oil and gas projects. The economic evaluation results influence the risk behaviour of investors and decision makers.
The qualitative evaluations consider the business drivers, stakeholder's perspectives, including the government in most cases. Other considerations for the qualitative assessment include things like risk appetite, assessment of project locations and energy transition policies. These areas of considerations highlight the need for investment decision making to be guided by quality decision analysis that can help put things in the right perspective and guarantee quality decisions even if it is impossible to guarantee the outcome of such decisions.
In this paper we review quantitative and qualitative decision-making techniques from literature. We also present practical cases where qualitative evaluations guide project teams to choices beyond the quantitative evaluation results.
Eliminating Associated Gas Flares in The Nigerian Stranded Marginal Field Oil Fields: The Otakikpo Field Strategy
Authors: Akinyemi Johnson , kala-otaji Tamunotroko 
Published: July 2023

Abstract
The Otakikpo marginal field was carved out of OML 11 and is situated in the southern part of the license. The field was discovered with Otakikpo-02 in 1983 and was further appraised with Otakikpo-03 in 1986. The wells encountered hydrocarbons in 4 stacked oil and gas bearing sands (C5000, C6000, C7000 and E1000). The field is operated by Green Energy International Limited (GEIL).
The field currently produces ~10,500 bopd with significant associated gas (AG) production from the wells with average GOR of ~1000 scf/bbl. Compositional analysis shows that the associated gas is rich in C3 – C4 components (~ 8%) and C5 – C7 (~ 3%) making it ideal for NGLs (LPG and condensates) extractions.
Most natural gas utilization projects require securing constant gas production contracts for between 10-20 years and for constant rates &gt; 50 MMSCFD. However, the Otakikpo field, the associated gas reserves do not meet this threshold and the production profiles are at best unpredictable.
To address these issues, an innovative strategy is required to accelerate reduction in the field's AG flaring. A qualitative and quantitative screening of the various gas utilization concepts against some critical decision drivers (AG production profile, scalability, CAPEX) led to the recommendation of a modular LPG extraction plant for the heavier components of the AG and Gas to Power for the lean gas.
The conventional approach of piping gas from a remote field needs to be replaced with a less orthodox technique of "bringing the plant to the gas". This eliminates the need for expensive pipeline and compression since the facility is within the Otakikpo field flow station. Furthermore, a modular scalable strategy with small footprint plant that is quick to deploy and easy to relocate was recommended as the best solution for the field.
The Operator successfully commissioned the 12MMSCFD modular LPG extraction plant and 6MW power generating plants. This scale of modular LPG plant will be the first to be installed in the country. This strategy could be adopted by other small fields in addressing AG flares caused by stranded pockets of gas located in oil fields in the Niger Delta thus supporting the Government's aspiration of eliminating AG flares.
Conceptualizing the Otakikpo Onshore Terminal: The First Indigenous Onshore Terminal
Authors: Akinyemi Johnson , Kala-Otaji Tamunotroko 
Published: July 2023

Abstract
The Otakikpo field development activities commenced in 2015 with the re-entry and completion operations on Otakipo-02 & 03 wells and the installation of a 10kbpd processing facility. Due to its proximity to the shoreline, an amphibious production and evacuation methodology was implemented. This consists of batch production into onshore tanks, a subsequent evacuation into offshore shuttle tanker via an installed 6" Km offshore pipeline and final transportation to a 3rd party FSO facility. The first phase of the field development was completed in 2017 and production declined from ~ 6500 bopd to ~ 4000 bopd by 2022.
Green Energy successfully executed phase 2 of the field development by drilling and completing two new development wells, Otakikpo-04 and -05 wells in 2022 and field production increased to circa 10000 bopd. The production facilities limit the field production to 12,000 bopd while the evacuation infrastructure could only effectively handle about 14,000 bopd. Moreover, the field's evacuation cost is very exorbitant mostly from the cost of hiring marine vessels (2 gunboats, 2 shuttle and 2 tugboats) and paying for CHA charges at 3rd party terminal. At lower production rates, the cost per barrel will be unsustainable.
It is for this reason that the Operator conceptualized a phase 3 development strategy to develop and install an efficient evacuation/export strategy and thus reducing overall OPEX $/bbl. It also plans to make the Otakikpo field a crude processing and export hub in the Eastern Niger Delta area. To achieve this, the operator plans to construct an onshore terminal and export infrastructure very close to the field. This consists of a scalable onshore terminal with an initial 750,000 barrels of oil storage capacity located within the field with a 360,000-bpd pumping and metering capacity for loading tankers. It also includes a 20" × 23km offshore export pipeline connecting the terminal to an unmanned single point mooring (SPM) crude offloading system. The terminal is expandable to store circa 2 million barrels of crude with a daily processing capability of 250,000bopd.
The proposed Otakikpo onshore terminal is conceptualized as a national infrastructure with potential to unlock significant stranded national reserves. It will be the first new onshore terminal in Nigeria in over 50 years, and first to be non-IOC owned and operated. Moreover, the terminal is expected to create significant value for the over 20 stranded marginal fields that are in proximity to terminal which would benefit from access to readily- accessible, cost effective and fit for purpose evacuation infrastructure.
This paper aims to highlight the justifications for the Otakikpo onshore terminal, lessons learnt during the conceptualization and design stages, status of the project, opportunities for future expansion and its potential role in the energy security of the nation in future.
Application of Lignin Polymeric Nanofluid as a Chemical Enhanced Oil Recovery Agent at Reservoir Condition
Authors: Al_Ani M. , Sidek M. A. , Jaafar M. Z. , Agi A. , Gbonhinbor J. , Ridzuan N. , Mahat S. Q. A. , Yakassai F. , Ngouangna E. , Oseh J. 
Published: July 2023

Abstract
Surfactant flooding constitutes part of the relevant enhanced oil recovery (EOR) technologies desirable for Malaysian oilfields. However, the high cost of synthetic surfactant production, high toxicity, susceptibility to high salinity reservoir condition, high adsorption rate and the strict regulation laid by government agencies in different countries has limited the growth of synthetic surfactant market in the post Covid-19 era. To solve this problem, the non-petroleum-based (biomass) surfactant can be used to replace the petroleum-based surfactant. Therefore, in this study lignin polymeric nanofluid (LPNF) was synthesized from sago bark using the method of ultrasonic assisted nanoprecipitation for EOR application. Besides, the surface morphology, functional groups, purity, structure and thermal stability of the lignin nanoparticles was determined using transmission electron microscopy, Fourier transform infrared spectroscopy, high pressure liquid chromatography, nuclear magnetic resonance and thermogravimetric analysis, respectively. The interfacial tension (IFT) of the formulated LPNF at oil-water interface was determined via a Kruss tensiometer. Thereafter, the ability of LPNF to alter the wettability of oil wet sandstone core was determined using a drop shape analyzer. TEM results indicate that lignin nanoparticles of size range 10-23 nm were produced. The zeta potential of -34 mV shows long-term stability of the nanofluid. The LPNF altered the wettability of the sandstone core from oil wet (133.3°) to water wet (10.2°), decreased IFT thereby indicating high propensity to increasing oil recovery at reservoir condition.
Overcoming Non-Technical Challenges in Well Abandonment – A case study of a field in the Niger Delta
Authors: Okonkwo Ngozi , Agbogu George , Olowu Babajide , Bougha Arthur , Reginald-Ugwuadu Onyinye 
Published: July 2023

Abstract
There is a new drive on well abandonment in Nigeria. Numerous technical challenges arise while safely delivering abandonment wells often due to missing & inaccurate historical data considering that some of the wells were drilled over 60 years ago. This challenge alone makes it an easy oversight from most rig and office-based teams to focus more on the technical challenges while losing sight of an equally important & often understated factor namely non-technical issues.
The well objective of decommissioning/abandonment is to install permanent barriers to effectively isolate the hydrocarbon bearing reservoirs from the freshwater reservoirs and the surface in an environmentally safe manner and restore the surface location as close as possible to its original state. What these objectives imply is that benefits (local employment during well intervention, freedom to operate dues and government entitlements as producing communities) are no longer accessible to the local host communities which bring forth a dimension that often times acts as a spanner in the works of efficient & effective abandonment operations.
This paper will address in detail the challenges encountered during a recent well abandonment campaign spanning 5 wells in the same calendar year, how the team effectively managed the non-technical issues and continuously improved from high NPT recorded in the 1st well to less than 10% at the end of the campaign without any safety incident. In this new era of focused abandonment in the Nigeria oil industry empowered by recent PIB signed into law, the knowledge and learnings from this project will help other operators who will undergo mandatory abandonment of wells in near & far future to appreciate and plan for these challenges.