bluuebunny/crossref_metadata_2025 huggingface dataset:
Formation Damage Assessment and Adsorption/Desorption Profile of New Phosponate-Based Scale Inhibitor at 350°F
Authors: Al-Aamri Jamal , Al-Dahlan Mohammed , Al-Yami Ibrahim , Hazzazi Hassan
Published: October 2018

The formation of calcite scale is induced generally through a change in pressure and temperature, which affects the saturation level of calcium and bicarbonate as the CO2 gas is released. Prevention of calcite precipitation through scale inhibitor squeezing job treatment is a well-known method for minimizing potential scaling. The selection of suitable scale inhibitor is important as its performance can be affected by the lithology and reservoir conditions. In this study, a scheme of screening new scale inhibitors was evaluated. The proposed scheme included the study of the adsorption/desorption characteristics of the scale inhibitor and its efficiency at higher temperature.

The proposed scale inhibitor treatment design included pre-flush/post-flush fluid and the SI main fluid in addition to the synthetic formation water (SFW). Lithium chloride was introduced to the main SI fluid as a tracer.

To study the SI fluid-rock interaction, core flood testing was conducted on the Outcrop Torrey Buff sandstone core plug. The results of the core flood was used to determine the change in permeability during the SI soaking and assess the formation damage. Ca, Mg and total iron in the effluents samples were used to study the dissolution of the plug. P and Li analysis were used to study the absorption/desorption behavior of the scale inhibitor during the 5 days of flooding and compared to the minimum inhibition concentration (MIC).

Core flood data showed the differential pressures versus the cumulative pore volume of the injected fluids revealed that around 20% of formation damage was encountered during the SI flooding, which is anticipated in sandstone rock due to high adsorption of the scale inhibitor on the rock. The desorption profile of the scale inhibitor showed that the proposed treatment scale inhibitor could keep its concentration above the MIC at ultra-high temperature.

The study revealed that the proposed phosphonate-based inhibitor showed effective performance at higher temperature. The desorption rate is adequate to keep the scale inhibitor concentration above the MIC. The scheme of study can be used to screen different scale inhibitors at higher temperature and to assess their adsorption/desorption characteristic.
Investigation of the Relationship Between Rate of Penetration and Mud Weight Based on the Hardness of the Rock
Authors: Alkinani Husam H. , Al-Hameedi Abo Taleb , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Alkhamis Mohammed M. , Alshawi Yousif Q. , Al-Maliki Madhi A. , Alsaba Mortadha T. , Amer Ahmed S.
Published: October 2018

The rate of penetration (ROP) plays a major role in drilling optimization, making it an important area of investigation. In this work, sensitivity and statistical analysis were carried out using data from over 100 wells in the Rumaila field, Iraq. The goal is to assess the effect of mud weight (MW) on ROP, to provide a method for estimating the recommended range for operational mud weight based on the hardness of the rock.

Drilling intervals from data collected from drilling reports from over 100 wells in the Rumaila field, Iraq, were categorized as weak, medium, hard, and very hard, based on UCS, depth, and lithology. Statistical and sensitivity analysis was conducted, developing correlation coefficients (CC) to represent relationships between rock hardness, ROP, and MW from field data. This methodology combines data from mud logging, daily drilling reports, and geological information to investigate the relationship between ROP and MW for different rock types and strengths.

It is well known that MW can dramatically impact ROP, and well documented in literature and laboratory studies. Several early studies focused directly on MW, clearly demonstrating the effect of MW on bit conditions, and therefore ROP. However, these studies do not include consideration of the hardness or lithology of the rock. There is also a strong discrepancy between results from different studies. Different literature concludes the relationship between MW and ROP is inverse, and in some it is direct.

For this study, field data have been gathered (more than 100 wells) to further investigate the relationship between MW and ROP, and how it varies with rock hardness. Field data have been categorized based on the hardness of the rock. The results showed that MW has an inverse relationship with ROP for the weak formation with a CC of -0.57. Thus, MW should be maintained as minimum as possible when drilling through the weak formation. On the other hand, MW has a direct relationship with ROP for medium, hard, and very hard formations with CC of 0.31, 0.4, and 0.42 respectively. Hence, MW has to be maintained as high as possible to maximize ROP for medium, hard, and very hard formations.

Large-scale collection and interpretation of field data were collected to demonstrate the effects of MW on ROP with varying rock hardness and lithology. While field data of this scale is inherent of interest, this analysis also investigates relationships previously unexplored and extends understanding of how MW effects ROP.
Survey of Big Data New SQL Database Systems for Real-Time Data Transfer in the Upstream Oil and Gas Industry
Authors: Djamaluddin Basirudin , Mohammed Salahadin
Published: October 2018

In less than a decade, there has been a tremendous evolution in the various storage solutions used to contain wellsite data in the upstream oil and gas industry. Many organizations from wellsite data management providers to the oil and gas operators themselves are moving away from traditional relational database management systems (RDBMS) and towards big data solutions.

There are several reasons for this evolution. First, data flow has increased at an unprecedented rate as the number of rigs increase and so has the data frequency rate. Second, the types of data from the sensors and data acquisition systems (DAQ) have also grown. Third, for data analytics that requires high-speed processing, it needs to be received in a timely manner so insights can be drawn for better, faster decision- making.

Big Data implementation known as NoSQL databases were proposed to handle conditions where: the data volumes are increasing exponentially, various types of data that are being transmitted or connected from various sources which are substantial for data analytics, and the last is the high-velocity streaming data that requires high-speed processing.

Moving in this direction is not without sacrifice. For example, companies adopting NoSQL give up several important factors, for instance, how the database handles transactions from multiple applications. Implementing NoSQL means giving up the benefits of Atomic, Consistent, Isolated and Durable (ACID). NewSQL comes as a promising new solution which offers the same scalable performance as NoSQL for the Online Transaction Processing (OLTP) read-write workloads while still maintaining ACID guarantees for transactions.

This paper will investigate, characterize and analyze the list of NewSQL databases in depth and develop comprehensive taxonomy for various critical aspects which come with them. We then will map the requirement of the data storage for handling upstream data to the proposed taxonomy so it can be used as a basis for analyzing each of the databases. At the end, we will predicate and highlight sorted databases which can be recommended for the implementation of next generation wellsite data storage in the upstream oil and gas industry.
Compatibility of Acid Precursors and Solvents with Sandstone Formations
Authors: Al-Ibrahim Hussain , Al Moajil Abdullah , Al-Yami Ibrahim , Al-Darweesh Sajjad
Published: October 2018

Organic acids and their precursors have been used to remove filter cake created by water or oil-based drilling fluids. Solvent and emulsifying surfactants are incorporated in the fluid recipe to solubilize oil residue and water-wet the surface of filter cake. Acids lost into the formation may interact negativity sandstone formation minerals and clays. The objective of this study is to assess fluid/rock interactions using high permeable sandstone core plugs.

Oil-based drilling fluids were used to create the filter cake. Formic and acetic acids-based fluid recipes were used at concentrations below their solubility limits. Mutual solvents and microemulsifying surfactants were added to the acid recipes to dissolve the oil residue and water-wet the filter cake. Compatibility, HT/HP fluid loss and coreflooding experiments, were conducted using the acid/solvent based recipes. Experiments were conducted at 250°F and 3,000 psi. XRD analysis was conducted to analyze solids generated after the reaction of sandstone core plugs with injected fluids.

Acetic acid-based fluid recipes were compatible with sandstone core plug. A Formic acid-based recipes showed a significant decrease in core plug permeability. XRD results showed presence of iron-based and calcium formate precepitations. Filtercake removal recipes showed effective removal efficiencies (e.g., 80-100 wt%).
The First Application of the Reinforced Thermoplastic Pipe in a Sour Wells in Saudi Arabia Gas Field
Authors: Bin Ziad Abdullah , Subaii Abdullah , Alshammari Fahad , Buali Muhammad , Fazaa Jamal
Published: October 2018

In a strive to reduce the domestic reliance on oil, Saudi Arabia continues to sustain and increase it is production of naturel gas by drilling and stimulating new gas wells in Gahwar field. The newly drilled wells by default will not have the required permanent surface equipment to flow the free gas and condensate to the gas plant during the testing process of the productivity of the well. This testing process may extend for days, particularly when the well undergoes fracturing stimulations where hundreds of barrels of stimulation fluids are pumped into the formation in high pressures to create artificial fractures into the pay zone to enhance the well productivity. Such operations require extended flowback periods to clean up the well in order to reach the required production fluid criteria. This paper will focus on the first successful application of the spoolable reinforced thermoplastic pipe (RTP) in Saudi Arabia gas field. A 10,500 ft of 4" high pressure-high temperature RTP line was temporarily spooled and connected from a newly stimulated well to a flowline of a pre exiting well which allowed to flow back a significant amounts of free gas and condensate to the gas plant. Testing separators were utilized during the flowback operation to insure a low water cut production to the gas plant. Challenges like large operating area, high H2s content, nearby oil and gas wells, the installation and dismantle process of the RTP line after completing the operation were faced and resolved during the implementation of this technology. Utilizing RTP during the testing period of the well saved the environment from unnecessary emissions of heat-trapping gases and is proven to be economically beneficial. However, it may not be possible to implement it in every well due to safety and geographical reasons.
Well and Layer Selection Method Study of CO2 Waterless Fracturing
Authors: Qinghai Yang , Siwei Meng , Tao Fu , Yongwei Duan , Shi Chen
Published: October 2018

CO2 waterless fracturing is a novel waterless fracturing technology. CO2 exists in the reservoir with supercritical state, and its fracturing stimulation mechanism is very different from that of water-based fracturing. This paper studies the physical and chemical properties of supercritical CO2 and reservoir adaptability of CO2 waterless fracturing.

Supercritical CO2 has the advantages of good fluidity and strong penetrability, which avail to form a complex network fractures. Through miscible phase with crude oil, absorption gas displacement, and reservoir energy enhancement, production and ultimate recovery are further improved. While the liquid CO2 has the disadvantages of poor proppant carrying capacity, high friction and low fracture opening. Based on CO2 waterless fracturing practices in Jilin oilfield, this paper summarizes physical parameters, operation effect and production situation of all wells, analyzes the main factors influencing productivity, and puts forward a set of well and layer selection methods of waterless CO2 fracturing.

Under the condition of existing CO2 thickening and resistance reducing technology, the selection of wells and layers is mainly carried out in 6 aspects. (1) Because the filtration of CO2 fracturing fluid is strong, the permeability of target reservoir should be lower than 5md in order to ensure stimulation effect of remote area. (2) CO2 can react with water and divalent metal ions to produce carbonate sediments to block existing pores and reduce reservoir permeability, so it is better for low water-bearing reservoirs. (3) Frictional resistance of CO2 is 1.9 times as that of conventional guar gum, so the target layer should be 3000m or shallower to reduce frictional pressure drop. (4) Energy increasing effectiveness of unit volume of CO2 is 1.9 times as that of slick-water, which is more suitable for stimulating undercompacted reservoirs. (5) There is no water phase in CO2 fracturing fluid, suitable for stimulating strong water-sensitive reservoirs. (6) CO2 is easy to dissolve in crude oil and greatly reduces its viscosity, which is suitable to stimulate heavy hydrocarbon reservoir.

Adopting above well and layer selection principles, CO2 waterless fracturing were implemented in 6 wells in 2017, and the key parameters, such as success ratio, sand adding amount, production capacity post-fracturing were comprehensively promoted, which effectively supported CO2 waterless fracturing development practices of unconventional reservoirs.
The Performance of the Popular PVT Correlations on Sudanese Crude Oils: A Statistical Study
Authors: Mohamed Abdelmjeed , Ahmed Musa , Mohamed Ismail , Abdein Moutaz
Published: October 2018

The knowledge of PVT properties is of a high importance in the petroleum industry, precisely, in oil and gas reservoirs development, engineering, and production. In the practice of petroleum industry, these properties are obtained by laboratory analysis from downhole fluid samples which are highly recommended to be taken in the early time of the reservoir prior to production to get representative reservoir fluid. It becomes a challenge when production is started as the fluid composition in the reservoir changes with changing the reservoir pressure, in such case PVT properties could be estimated using measured data on the surface separator, well head, offset field, etc. However, in many cases this data is not available and the only source to estimate these properties is the empirically derived correlations. In fact, there are many correlations that have been developed in the past seven decades for different geological areas. Nevertheless, these correlations are merely reliable for a specific range of data. Therefore, significant errors might yield when these correlations are applied for different regions and crude oils.

This work is the first regional and formal analysis that studies the performance of the most popular PVT correlations and introduces a new set of correlations that estimate some of the PVT properties of different Sudanese crude oils which are: bubble point pressure (Pb), solution gas-oil ratio (Rs), and oil formation volume factor (Bo), at pressures below the bubble point pressure.

The data was obtained from different Sudanese oilfields, to represent a wide range of data. Then, the data was analyzed, prepared and fitted with correlations using non-linear regression techniques. Afterwards, statistical analyses were performed, and the new correlations were compared with the existing correlations to prove their applicability using the most common statistical parameters, i.e. average absolute percentage error, standard deviation and R-square.

The Statistical Error Analyses (SEA) show that all the popular existing correlations yield a variable range of accuracy when these correlations are applied to our database and the proposed correlations were found to be superior to all the popular existing correlations in terms of accuracy when applied for this specific region. Eventually, the performance of the newly developed correlations was tested against each oilfield individually to ensure their accuracy, and it was found that the error varies widely from field to another.

It is concluded from this study that PVT properties vary regionally and recommendation comes to perform such study before using such correlations in estimating PVT properties for a specific region.
The Challenges and Lessons of Enhanced Oil Recovery Using Sequestrated CO2
Authors: Odesa David
Published: October 2018

The use of CO2 for enhanced oil recovery is a proven technology capable of increasing oil production and addresses energy security issues from known resources. In this work, we considered Carbon (IV) Oxide CO2 capture in a flowstation Mystras FPSO for re-injection in a 32km away depleted vertical Okono-3 Well in Okono field, Offshore Niger Delta. The study considered the screening of storage site, CO2 post-combustion capture using monoethannolamine (MEA), analytical determination of the minimum miscibility pressure (MMP), transportation and injection of captured CO2. The economics of the capture process and the risks of leakage over a long time were also considered. About 6.9433mmscf/day of CO2 will be captured annually and re-injected into Okono-3 well over a period of one year. With 9416ft as Point-of-Injection (POI) for CO2-enhanced oil recovery. CO2-EOR is a proven tertiary recovery technology which allows the recovery of an additional 10 – 20% of the original oil in place from depleted or marginal wells (Tzimas et al., 2005; Stevens et al., 2001).
Particle Swamp Optimization of PVT Correlation
Authors: Sylvester Okotie
Published: October 2018

Pressure-volume-temperature (PVT) properties are very paramount in the evaluation of oil and gas performance. They serve as input data in most reservoir engineering calculations such as material balance equation, reserve estimate, reservoir simulation/study. PVT properties are obtained from laboratory experiment by sampling the fluid and/or empirical developed correlations. Laboratory measurements of PVT properties are usually capital intensive and such are nor readily available during reservoir performance evaluation, hence, petroleum engineers resorted to using existing empirical correlations to generate these properties as the reservoir pressure declines. Often time, the PVT data obtained from empirical correlations do not agree with the experimental data, thereby yielding a considerable amount of error. Hence in this study, Standing’s correlation for estimating the solution gas-oil ratio and Kartoatmodjo and Schmidt correlation for estimating the formation volume factor were optimized using a particle swarm optimization algorithm to minimize the error associated in estimating these properties from experimental analysis at various depletion pressure. PVT data from differential liberation test was used to validate this study’s correlation and the result obtained shows that the optimized correlation for this study matches closely with the experimental values, also the newly optimized correlations was validated with other models and the results gave the least average relative error of 3.34 and a correlation coefficient of 0.998 after 216th successive iterations for the optimized Standing’s correlation and average relative error of ±0.00065 and correlation coefficient of 0.99996 after 154th successive iterations for Kartoatmodjo and Schmidt.
Evaluation of Water Injection Performance in Heterogeneous Reservoirs Using Analytical Hierarchical Processing and Fuzzy Logic
Authors: Oluwajuwon Ifalade , Olugbenga Falode
Published: October 2018

Heterogeneous reservoirs are reservoirs containing many thin bed layers which may or may not be connected and are separated by low permeability barriers. After primary recovery, they are made to undergo secondary recovery, most commonly water injection. There is great difficulty in evaluating the efficiency of this process analytically due to the degree of heterogeneity of the reservoirs. Getting data for analytical solutions also has high economic implication. Fuzzy logic has found extensive use in engineering problems that are too complex to be solved using crisp logic. Zhao et al developed a model using Analytical Hierarchy Process (AHP) and Comprehensive Evaluation method of Fuzzy Logic by generating comprehensive evaluation coefficients (E2 values) for each well group. It however under-predicts or overestimates efficiency when there are factors which have outlying values (which may be due to gas caps, permeability jails or thief zones).

This paper seeks to develop a model using AHP and Controlled Fuzzy Logic to address the existing challenges in the above model. AHP is used to attach weights to the factors influencing performance namely; incremental oil production, water absorption ratio, and producing degree of waterflood. The E2 values are then generated for wells by introducing a new membership function.

The two models were applied to data from Ba fault block and the results compared. Both models were applied to data with outlying value and the results were compared. Results were similar for the former case but for the later, Zhao et al’s model predicted much lower efficiencies for wells it had already considered more efficient. The controlled Fuzzy model retained close E2 for both cases.

This model can help in prioritize water allocation to well groups in limited water supply, decide on introduction of EOR like acidizing or fracturing, cut cost on inefficient wells using the cumulative E2 distribution table.
Economic Evaluation of the Dual Petroleum Tax System Proposed in the 2017 Nigeria Fiscal Reform Framework
Authors: Amiesa Fubara Susan , Omowunmi Iledare , Joseph Akinlawon Adeyemi
Published: October 2018

Petroleum taxation is an instrument of government use to create a crucial rent sharing balance between oil and gas companies and host government. The petroleum profit tax imposed by the Nigerian government on upstream petroleum operators is an example. However, the complexity of the petroleum taxation due to the continued evolution in the international crude oil market dynamics, due to geogolical, technical, economic and political factors, prompts the quest for a tax system that will accrue a fair revenue to the government with acceptable returns to multinational oil companies. The propostion of a dual tax system in the 2012 PIB and 2017 Nigeria Petroleum Fiscal framework is designed to equitably satisfy stakeholders expectations. Concerns on how fair the dual tax system will be to the investor and government motivated the essence of this paper. The paper attempts to evaluate the proposed tax system in PIB 2008, PIB 2012 and Petroluem Fiscal Policy 2017. The paper applied a deterministic R/T system cash flow model for a continental shelf to rank the perfomances of the fiscal terms proposed in PIB 2008, PIB 2012 and in the 2017 NPFP document. From our analysis, we discovered that the economic metrics for the project depicted a better profitability for the operators under a dual tax system than a single tax system within the contex of our cost assumptions and profile. However, the same feat was not recorded for the government take as the dual tax system led to a slight decrease in the government take statistics rather than an increase. We considered this slight decline as a positive trade off that debunks the assumption amongs shareholders that the 2017 NPFPF dual tax system accrues more benefits to the government. Hence, we recommend the implementation of dual tax system as a favourable option for the investors and government.
Embedding and Operationalizing Sustainable Development Goals in the Nigerian Oil and Gas Industry
Authors: Ite Dr Uwem
Published: October 2018

The concept of sustainable development emerged from global public pressure in the 1980s and ultimately forced itself onto the agenda of governments and international institutions. It is now embraced as the global standard for measuring development objectives and performance in both developed and developing countries. The emergence of the Millennium Development Goals (MDGs) in 2000, and its subsequent replacement by the Sustainable Development Goals (SDGs) in 2015, clearly shows that the concept has indeed made significant progress by moving from global rhetoric and debates to local practice and action. The SDGs aim to address economic, social and environmental challenges. Member states of the United Nations (including Nigeria) are expected to use the SDGs to frame their development agendas, while clearly recognizing that the private sector has an important role to play in this regard. There is no doubt that the oil and gas industry is central to sustainable development in many national economies. Oil and gas are key pillars of the global energy system. As such, they are critical drivers of economic and social development. Although the industry contributes to sustainable development in several ways, its operations and products potentially have negative impacts on a range of areas covered by the SDGs, including communities, ecosystems and economies. Within the context of sustainable development in Nigeria, the overarching aim for the Nigerian oil and gas industry is to do business responsibly by contributing to society; minimizing risks and doing no harm. This paper demonstrates that with careful planning and implementation, the Nigerian oil and gas industry can contribute across all SDGs by enhancing its positive contributions as well as avoiding or mitigating the negative impacts associated with its operations. Three fundamental steps are necessary in this regard, namely: identification of relevant SDGs; stakeholder engagement and collaboration. The Nigerian oil and gas industry can embed and operationalize the SDGs in their core business practices by incorporating carefully chosen and relevant SDGs into their corporate systems, policies and processes.
Analysis of Vibrations in Drilling Systems
Authors: Osogba O. J. , Otamere B. , Abdullahi G. S.
Published: October 2018

Over the years, drillstring vibrations have become a major issue in the oil and gas industry. The search for energy has led operators to encounter various unconventional conditions such as high temperature, high pressure, etc. in their quest for oil and gas. Drillstring vibrations amongst other problems are regularly encountered in such conditions, leading to tool damage, increased downtime and other adverse problems. In this work, an analytical approach was adopted to investigate the major parameters that affect drillstring vibrations and a viable control method was recommended. The vibration models were analyzed and a modified model was developed to fit the standard drilling conditions, starting from the top of the drillstring down to the formation being drilled. Considering the Parameters which were often neglected in the works of this nature such as mud density and formation fracture pressure were investigated in order to understand the extent of their contributions to drillstring vibrations. Using standard drilling conditions for the simulations, we were able to identify the key parameters which significantly affected the vibration profiles. The data obtained from the simulations were used to obtain a markedly better profile which showed a marked reduction in amplitude. The analysis of the effect of all considered parameters to the vibration profile led to the conclusion that weight on bit / torque on bit and rotary speed are the key factors that affect drill-string vibrations and that the density of the drilling fluid used make little or no difference why formation fracture gradient caused a reduction in drillstring vibration as it increases.
Rain Water Quality Evaluation in a Typical Gas Flaring Environment in the Niger Delta
Authors: Ogolo Naomi Amoni , Ugwu Paschal , Ukut Imo , Otokpa Martins , Onyekonwu Mike
Published: October 2018

Environmental pollution is one of the major consequences of gas flaring. In the rural oil producing communities of the Niger Delta where this age long practice is common and a large portion of the population use rain water for domestic activities, it is imperative to evaluate the rain water quality in these environments. In this work, a hundred samples of rain water were collected within a period of two years from a typical community where gas flaring has been dominant for several decades. The samples were analyzed in the laboratory for pH value, turbidity and nitrite content, and the results were compared against the World Health Organization (WHO) standard for water quality.

The study shows that the rainwater samples collected from the gas flaring zone had an average turbidity value of 22.58NTU, an average pH value of 6.75 and contained an average of 2.6mg/l of nitrite. However, when considered separately, some rain water samples met the WHO standard while others did not. It was observed that about 61% of the samples considered met the WHO standard on turbidity of 15NTU for rain water and 17% of the samples met the standard for drinking water which is 5NTU. 26% met the lower pH standard of 7.0 for drinking water while 64% met the pH standard of 6.5 for rain water. 60% met the WHO requirement for nitrite content of 3mg/l but generally, about 39% of the samples did not meet the WHO standard for rain water quality. These test parameters indicate that the level of rain water pollution in this gas flaring environment is high and unhealthy especially for the ecosystem system. Thus, drastic measures need to be taken to stall gas flaring in the Niger Delta.
Fatigue Risk Management: Effective Solution to Workplace Stress in the Petroleum Industry
Authors: Linda Dennar , Nsikak Ntia , Afolabi Iboh , Folusho Alamina , Nayagawa Mbursa J. , Chima Emelle , Suleiman Ahmed
Published: October 2018

The nature of operations in the petroleum industry involves a significant amount of process and personal safety risks. Industry operators and service providers desire to achieve the safety goal of no fatalities or harm to personnel, and no damage to assets and environment.

Most operating companies and service providers have over time developed well-structured frameworks for Process Safety Risk Management. Aspects of personal safety especially operations-related are also well managed. A significant number of incidents have resulted from human factors related to stress and fatigue. Fatigue is a state of sleepiness with the associated lack of mental alertness caused by sleep deprivation. It is imperative that the industry recognizes the threat posed by fatigue and put the right measures in place to minimize the associated risks.

This paper intends to raise awareness on the impact of fatigue in the petroleum industry and recommend a framework for Fatigue Risk Management (FRM). A structured framework entails embedding of FRM Systems, which include studies, gap analysis, closure plans, and development of FRM plans, implementation, audits, and reviews.

The FRM system will ensure a safe working environment using a risk model to review outcomes and recommend actions. The embedment of this system which is based on Safety Management System (SMS) in the workplace ensures appropriate mitigations, effective controls, timely implementation, periodic audits and reviews. This system may be deployed in all areas of petroleum industry operations spanning Exploration and Production to the downstream sector. Similar models have been deployed in other industries with success.
Towards Transparency: Best Practices for Improving Community-Company Relations in the Nigerian Oil and Gas Sector
Authors: Ante M. A. , Ante A. E.
Published: October 2018

Oil and gas exploitation is a process of varied steps from prospecting and exploration to the production stage. As such, the overall success of such venture is dependent on success at each of these stages. While every step is critical, we highlight the important phase of community/company relations, which in fact is not a phase/step but a continuous aspect of the exploitation process as long as a company undertakes oil and gas development work in the community and even afterwards. Issues of land acquisition, memoranda of understanding, environmental issues and technical transparency (without disclosure of proprietary information) have increasingly caused misunderstanding and led to impasse which are detrimental to the causes of all parties involved. The objective of this work is to drive towards a sweet spot where the community and company can coexist for mutual economic attainment.

In the lens of a Petroleum Engineer and a Lawyer, we review current practices and best-practices and proffer better solutions on improving community-company relations tailored to the Nigerian sphere based on knowledge of our clime. Under applicable laws, acts and regulations, we review the nature of land acquisition and where errors have been made in this area causing discord; as regards memoranda of understanding we highlight standards for social and environmental outcomes. We also cover operational and environmental issues and how best these could be addressed on the engineering angle

We recognize that just like no two developmental projects are the same, there is therefore no one-size- fits-all solution but instead, guidelines and better understanding of issues from the technical angle and from the perspective of the law will help to remove the veil of mistrust and help communities and companies achieve a positive discourse at the table.

As we mark 60 years of oil production, the oil and gas industry has and will continue to be a major driver of economic growth in Nigeria. As such, it is necessary to model what real, perceived and impactful community-company partnership is composed of. Success at the community-company level will no doubt provide a foundation for success at the other levels of development and in turn grow our communities, its economy and people and our great nation, Nigeria, at large.
Optimization Of The Production Of High Quality Gasoline Blend From Different Oxygenates
Authors: Oduola M. K. , Nwangwu C. N.
Published: October 2018

Gasoline is a highly flammable liquid derived mainly from crude oil that is used primarily as an energy source for internal combustion engines. To be competitive, gasoline must meet certain standards of high quality such as Octane number, Ried Vapor Pressure (RVP), and minimal environmental pollutions. This work aims at optimizing the production of a high-quality gasoline blend that meets the Octane number, RVP, Economic and Environmental standards, using varying oxygenates. The gasoline blending was executed by employing the linear programming solver application in Microsoft excel using four blending components namely the Fluid catalytic cracking gasoline (FCCG), Straight run naphtha (SRN), Straight run gasoline (SRG), Butane, and varying Oxygenates. The Blending process was simulated in ASPEN HYSYS simulation software, and the output product was tested for pollutant emissions in the same software. The selected blend was further optimized to minimize emission using the Response Surface Methodology in MINITAB version 18. Upon gasoline blending optimization and emissions testing, four blends met our specifications namely, the MTBE blend, the ETBE-blend, the Ethanol-blend, 1-Butanol blend. After a simple weighting method, the Ethanol was selected as the optimal blend having a net savings of 67.09 tons/year and 476tons/year of NOx and TVOC emissions respectively, a net increase of 16.35 tons/year of TTC emissions. The Blend was further optimized using RSM. The optimization results showed that SRG was the main contributor to NOx emissions, ethanol was a significant contributor to the TTC emissions while Butane had no effect of both emissions. The new optimized ethanol-blend gave a further 90.42% reduction in NOx emissions, and 67.85% reduction in TTC emissions, but with an increased amount of ethanol in the blend. The economics of a gasoline blending plant was evaluated, giving a pay-back period of 2.46 year, NPV @ 10th year of $177.6 million, an internal rate of return of 57.36%, and a profitability index of 3.04. This showed that the process would be highly profitable.
Impact of Salinity on Oil Recovery during Waterflooding: An Experimental Approach
Authors: Stanley Okafor Ikechukwu , Ebenezer Ubani Chikwendu , Obi Onyekonwu Mike
Published: October 2018

Improving the recovery factor of conventional oil reservoirs is a critical factor in offsetting the inevitable decline of oil fields and keeping step with the world's demand for hydrocarbons. This paper describes a laboratory experiment to investigate the impact of brine salinity on oil recovery during waterflooding and to ascertain if there exist any relationship between salinity and type of oil in terms of recovery. During the flooding experiment, the cores were individually flooded with the high salinity and low salinity recovery brines in a secondary stage recovery process, to recover the crude oil (heavy and light) with which they were earlier saturated with. Recovery brine salinity ranged from 5000ppm to 30000ppm and a distilled water of 0ppm. Results obtained showed that high salinity recovery brine showed better recovery than the low salinity brine, for both the heavy and light oil. The high salinity brine recovered 61% and 63% of the heavy and light oil in place respectively, while the low salinity brine recovered 51% and 56% of the heavy and light oil in place. The results obtained are attributed to reduction in viscosity ratio, wettability alteration, reduction in interfacial tension and natural variations between cores. There was no definite relationship between crude oil type and the salinity of injected brines. It is recommended that studies to investigate the impact of salinity on cores containing clays should be carried out. These studies if successful will help in our bid to increase recovery factor during secondary recovery of the stranded oils in discovered fields.
Uncertainty Modelling in Multi-Layered Reserve Estimation Using Monte Carlo Simulation
Authors: Inuwa Mohammed Auwalu , Abdurahman Hassan , Dodo Ibrahim Sulaiman , Mohammed Adamu Bello
Published: October 2018

Risk and uncertainty are important aspects in petroleum engineering, which must be analysed and considered in reserve estimation. The petrophysical parameters such as porosity, permeability, saturation, net thickness and acreage that are pertinent to volumetric reserve estimate are measured with some degree of uncertainty and error. Data sources and means of acquiring data may also result in uncertainties in reserve estimation and forecasting reserve. However, oil and gas companies are indeed concerned with accurate oil and gas reserves and original hydrocarbon in place. In addition, they are interested in recoverable reserve and the time for the recovery process with certain degree of certainty and accuracy. These estimates are rarely accurate or the level of uncertainty sometimes make oil and gas project not economically profitable.

The two established volumetric methods of reserve estimation are deterministic and stochastic. In both approaches, mathematical formulae are used to estimate volumes of hydrocarbon. However, the deterministic approach uses single value input parameters that are considered representative of the reservoir. Thus, the corresponding volumetric value obtained is a single best-estimate. On the other hand, stochastic reserve estimation considers the fact that each parameter cannot be represented with a single value due to the uncertainty and heterogeneities associated with these parameters, but it should be included in an interval and model using appropriate normal, lognormal, or triangular distributions.

In this study, uncertainty in multi- layered volumetric reserve estimate was quantified using Monte Carlo simulation for all the uncertain parameters, and the total recoverable oil obtained from deterministic method subjected to the Oracle Crystal Ball software for sensitivity analysis. Pessimistic, most likely and optimistic reserve values were obtained with their respective certainty for all the simulation scenarios. Error parameters such as Standard deviation, mean, variance, skewness, kurtosis, and mean standard error were quantified. Very low value of 0.00241 as coefficient of variation indicated that there was a high level of confidence in this estimation based on the modelling of input parameters; and this resulted to 90%, 50% and 10% probabilities of the oil in place calculation as (130.22MMSTB), (88.31MMSTB) and (58.13MMSTB) respectively. Therefore, use of Monte Carlo simulation to modelled risk and uncertainty would increase investors' confidence, and reduce the risk and uncertainty associated with reserve estimates in general terms.
Nigerian National Petroleum Fiscal Policy – Fiscal Levers & Attendant Impact on Value of Oil Projects
Authors: Segun-Oki Hakeem , Lawal Hafiz , Filani Oladapo
Published: October 2018

Efforts to reform the Nigerian Petroleum Industry have been ongoing since 2008 when the Petroleum Industry Bill (PIB) was presented to the 6th National Assembly. The PIB was conceived to address three central themes which coexist in a delicate equilibrium: increase economic rent to government, resolve long standing socio-environmental issues and encourage a stable investment climate.

However, due to a lack of traction in passing the bill in its all-encompassing form, in 2016 the current administration took the judicious approach of splitting the PIB into four bills to expedite assent to law. One of which is the Petroleum Fiscal Framework Bill (PFFB). This Bill tables the National Petroleum Fiscal Policy (NPFP) as the go-forward fiscal framework for the Nigerian Petroleum Industry.

Industry consultation on the draft NPFP is currently ongoing, being led by industry trade groups such as the Oil Producers Trade Section (OPTS) and the Independent Petroleum Producers Group (IPPG). The outcome of these consultations will be incorporated into the final version of the PFFB to be enacted into law.

This paper makes both a quantitative and qualitative analysis of the impact provisions in the draft NPFP have on the value of oil projects under Production Sharing Contracts (PSC). It proffers mechanisms for arriving at a balanced fiscal package that ensures both the host government and investors receive fair value.
Life Cycle Water Management in Oil Production- The Good, The Bad and The Ugly
Authors: Ayeni Olukayode , Ayeni Olumide , Olatope Victor
Published: October 2018

There are quantum literatures, technical papers, etc on water management in the oil and gas industry. It is a very wide issue and with significant interest due to cost and environmental implications. The focus of this paper is water management in relation to oil production with the purpose of given the industry professional an all-round understanding of life cycle water management. Since by nature the oil is layered above water and the most common reservoirs drive mechanism is underlying aquifer (water), water production is therefore inherent in exploitation of oil. The impact of water in oil production could be good, bad or even ugly. This paper will discuss the various water management techniques from the drilling phase, through completion, production, transportation and treatment at processing facilities. Though basic, this is substantially fundamental. An improper management during any of the phases could prove very costly down the road to the promised developed ultimate recovery for a well completion and even overall recovery from the reservoir.

With water production, comes the associated cost of water processing and disposal. It is the view in this paper, that practices and technology should be deployed to delay and minimise water production where appropriate. In today's lower oil prices for longer world, the industry must always strive to reduce their UOC (Unit Operating Costs) to remain profitable and competitive. There are published estimates of water handling costs being as high as 50 cents per barrel of water produced. Reduction in this cost will surely impact the operating company bottom-line.

Though there are extensive literature that addresses specific challenges with water management in discrete phases of operation, this paper will attempt to provide a life cycle view, hence its uniqueness. It also highlights practical solutions that are tried and tested.
Reduction of Operating Cost Through Pipeline Flow Network Optimization
Authors: Onwuemene Onyeka Chiazor , Happiness Deele , Fadayomi Lanre , Okwudiafor Paul , Jabar Sheriff
Published: October 2018

Optimized flow assurance was achieved in an offshore Well Head Platform (WHP) via the use of a Surface Pipeline Network Modelling Tool. The WHP has 15 flowing wells with a flexibility of diverting the wells into either a 14" or 10" departing pipeline for processing on two production facilities. Because of high departing pressures on both pipelines, Drag Reducing Agent (DRA) injection was continuously introduced at an increased production operating cost to manage backpressures that impaired well deliverability.

The approach is based on simulating various Well flow configurations via the 2 production pipelines with the aim of reducing DRA injection to the barest minimum or zero from an injection rate of 5 gal/hr. Test results (GOR, Liquid rate, solution gas, BS&W, API gravity etc.) of all affected wells were utilised as input parameters during the simulation exercise. Various flow configurations were arrived at as DRA injection rate was steadily reduced from 5 gal/hr – 2gal/hr over a 6-month period. DRA injection rate of 0gal/hr was achieved after 1 year.

The developed Surface network model served as a guide in the process of eliminating the need for DRA injection. DRA reduces the turbulence in pipelines to allow a much efficient flow. This in turn aids well productivity by reducing back pressure on flowing wells. To assure the use-ability of the simulation model, it was validated by using it to match the flow characteristics of a different production network in the field using well test records and pipeline properties (roughness, length, diameter, et al.).

In conclusion, the Surface Pipeline Network Modelling Tool presented a technical basis for making an important operational and cost-effective decision which persists till today. A cost savings of ~$1.4MM/year in 2016 and subsequently ~$3MM/yr as best multi-phase Well flow configuration in the 2 pipeline systems was achieved.

The importance of this optimization is the need to fully exhaust the opportunities that software tools present in critical decision-making processes which could aid cost savings and solve knotty operational & HSE issues when robustly deployed