Oilfield Projects Research Articles

An Overview of Geological CO2 Sequestration in Oil and Gas Reservoirs

A tremendous amount of fossil fuel is utilized to meet the rising trend in the world’s energy demand, leading to the rising level of CO2 in the atmosphere and ultimately contributing to the greenhouse effect. Numerous CO2 mitigation strategies have been used to reverse this upward trend since large-scale decarbonization is still impractical. For multiple reasons, one of the optimal and available solutions is the usage of old depleted oil and gas reservoirs as objects for prospective CO2 utilization. The methods used in CO2 underground storage are similar to those used in oil exploration and production. However, the process of CO2 storage requires detailed studies conducted experimentally and numerically. The main goal of this paper is to present an overview of the existing laboratory studies, engineering and modeling practices, and sample case studies related to the CCS in oil and gas reservoirs. The paper covers geological CO2 storage technologies and discusses knowledge gaps and potential problems. We attempt to define the key control parameters and propose best practices in published experimental and numerical studies. Analysis of laboratory experiments shows the applicability of the selected reservoirs focusing on trapping mechanisms specific to oil and gas reservoirs only. The current work reports risk control and existing approaches to numerical modeling of CO2 storage. We also provide updates on completed and ongoing CCS in oil and gas reservoir field projects and pilots worldwide.

Study Describes Challenges, Opportunities of CO2 EOR in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209468, “CCUS In China: Challenges and Opportunities,” by Hu Guo, China University of Petroleum; Xiuqin Lyu, Sinopac Northwest Oil Field Company; and En Meng, China University of Petroleum, et al. The paper has not been peer reviewed. One of the most attractive carbon capture, usage, and storage (CCUS) applications in China is that of carbon dioxide (CO2) enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 presents an important path for China. The complete paper reviews the progress of CCUS technology in China. The current challenges of CCS EOR include high capture costs, small scale, low incremental oil recovery, and huge capital input. The costs can be significantly reduced when the scale is enlarged to the commercial level and transportation costs are further reduced by pipelines or trains. Importance of CCUS At the time of writing, 49 CCUS pilots or field tests had been conducted or were under construction in China. CCUS demonstration projects were small-scale, and no projects involving more than 1.0 million tons of CO2 per year (mtpa) were conducted. 1.3 million tons of CO2 were estimated to be injected in 2020 for EOR use. The authors reference a study that mentions nine CO2 EOR projects. Among these, the Jilin oilfield project was notable for its size of 2.0 million cumulative tons of CO2 injected. CO2-enhanced coalbed methane was also an attractive option for China, and several field tests were conducted by CNOOC and its partners. Another notable CCUS demonstration project involved the Shaanxi Jinjie power plant. This was the largest coal-fired power postcombustion (PC) CO2-capture project, with a capture capacity of 0.15 mtpa. The project began in November 2019. In January 2021, equipment installation was completed. By June of 2021, 168 trial operations had been passed. The captured CO2 will be used for EOR. This demonstration project will gain knowledge to reduce PC CO2 emissions, a great challenge for China because the majority of electricity is based on coal combustion. Gas processing and power plants rank first for the US in terms of CCUS project numbers. Power plants also rank first in the number of CCUS projects for China, but the number of natural-gas-processing projects was much less.

Insights From Ivar Aasen Oil Field Project in Norway

The goal of this chapter is to present lessons learned and insights gained from managing the Ivar Aasen project. Lessons were collected through 28 interviews with key project members and contractors. Findings show that Ivar Aasen was executed under considerable uncertainty regarding the market situation, access to suppliers and was completed under very strict time schedule. The project was complex with over 140 suppliers and subcontractors that were globally distributed. The project was also the first major project for the operator company. Findings shows that the underlying context of the project was a source of several challenges encountered during execution. In spite of these challenges, the project was completed on budget and on schedule and now the field is in full operation. The paper presents a narrative description of the challenges encountered as well as the factors that contributed to project success. Based on insights gained, the paper presents 18 recommendations that should be adhered to succeed with projects that exhibits similar characteristics as Ivar Aasen project.

Insights From Ivar Aasen Oil Field Project in Norway

The goal of this chapter is to present lessons learned and insights gained from managing the Ivar Aasen project. Lessons were collected through 28 interviews with key project members and contractors. Findings show that Ivar Aasen was executed under considerable uncertainty regarding the market situation, access to suppliers and was completed under very strict time schedule. The project was complex with over 140 suppliers and subcontractors that were globally distributed. The project was also the first major project for the operator company. Findings shows that the underlying context of the project was a source of several challenges encountered during execution. In spite of these challenges, the project was completed on budget and on schedule and now the field is in full operation. The paper presents a narrative description of the challenges encountered as well as the factors that contributed to project success. Based on insights gained, the paper presents 18 recommendations that should be adhered to succeed with projects that exhibits similar characteristics as Ivar Aasen project.

Experimental investigation on effect of reservoir conditions on stability and rheology of carbon dioxide foams of nonionic surfactant and polymer: Implications of carbon geo-storage

Carbon dioxide (CO2) injection, in form of a viscous foam, is one of the effective techniques to control premature CO2 breakthrough in subsurface carbon storage and utilization (CSU). Polysaccharides are often used in oilfield and its use for developing viscous CO2 foam will make the process reservoir compatible and economic. However, their efficacy should be tested at real conditions to promote better CO2 utilization in oilfield projects. This study aims to quantify the role of subsurface conditions viz., pressure, temperature, and salinity on CO2-foams prepared by non-ionic polymer (guar gum, 4000 ppm) and surfactant (TX-100, 0.25 mM). Salts i.e. potassium chloride (KCl) and magnesium sulfate (MgSO4) of varying concentration (0–8 wt%) were used. Increasing salt concentration were found to significantly affect foam stability (maximum fall of 88.88%) and CO2 molality in surfactant-polymer (SP) solution (by 73.1% at 70 bar pressure). KCl showed a greater reduction (≈8–15%) than MgSO4 (6–12%) however, increasing surfactant amount had negligible impact on CO2 molality. Additionally, microscopic analysis was performed in which initial bubble size (i.e. 40-60 μm) due to coalescence phenomenon was observed to increase to (400–460 μm) after 1 h. CO2 foams exhibited non-Newtonian shear thinning behavior where foam viscosity and elasticity were positively influenced by increase in pressure, which suggested foam potential for enhanced oil recovery (EOR) and carbon storage in subsurface environment. Foam viscosity decreased with increasing salt concentration (fall of maximum 55% when compared to zero salt content) and temperature resulting at 90 °C, foam viscosity reduces to a value of 0.05 Pa s at pressure≈ 70 bar. Finally, dynamic rheological measurements were reported to visualize viscoelastic response of foams. The viscoelastic response of CO2 foams by strain sweep measurements reported a maximum fall of 60% while 40% reduction in case of frequency sweep measurements was observed. Also, foams exhibited both elastic and viscous effects with clear cross-over between G′ and G″ at each test pressure and temperature.

Compositional simulation model and history-matching analysis of surfactant-polymer-nanoparticle (SPN) nanoemulsion assisted enhanced oil recovery

BackgroundSimulation plays a pivotal role in the design of enhanced oil recovery (EOR) processes based on reservoir and in-situ fluid conditions. A robust compositional model, using a complicated multi-component nanoemulsion injection fluid, was developed to describe the performance of nanoemulsion flooding to predict their feasibility for pilot oilfield projects. MethodGemini surfactant/polymer/nanoparticle stabilized Pickering nanoemulsions were prepared by high-energy method and characterized to assess core-flooding performance. During simulation, a Cartesian grid model with fixed bulk volume, injection flow rate, well completion parameters and rock-fluid properties was employed. Core-flooding experiments were performed in steps, involving ~2.16 pore volume (PV) brine injection, ~0.90 PV nanoemulsion injection and ~1.50 PV chase water injection. Significant findingsOil saturation map and relative permeability data analyses showed that the wetting nature of sandstone core altered from intermediate-wet to strongly water-wet condition. Tertiary recoveries were obtained in the range of 21-27% of the original oil in place (OOIP) for different surfactant/polymer/nanoparticle (SPN) compositions of injected nanoemulsion fluids. Flooding simulation studies showed good history matching of production data within ± 6% between experimental and simulated results. In summary, the efficacy of SPN nanoemulsions as an EOR fluid was corroborated with the aid of numerical simulation analyses.

West Africa Salt-Zone Cementing Best Practices: Laboratory Evaluation and 5-Year Field Application Review

Summary To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.

DIGITAL OIL FIELD FROM DATA TO REAL - TIME DECISION MAKING -SMART WORKING FOR OPERATIONS EFFICIENCY

Digital Oil Field (DOF) project in OMV Petrom aims to remotely monitor, troubleshoot and optimize operations and maintenance data and activities in a modern manner, and to foster value creation through increased integrated and reliable performance data availability to skilled professionals in order to facilitate the right decisions. DOF Project started as a pilot in an oil field, covering a large area of automated wells and facilities. The pilot field is operating around 400 wells equipped with PCP (progressive cavity pump) and more than 70% automated facilities consisting of: 14 MPSs (Meter Point Skids), 2 PMANs (Production Manifolds) and 1 OMS (Oil Metering Station), all connected to SCADA systems.

Prioritizing and Providing Sound Pollution Control Strategies at the CPF of North Azadegan Oilfield Project

Among the harmful occupational factors, noise is the most common exposure in the oil industrial workplaces. The present study aimed to prioritize sound pollution areas in central processing facilities (CPF) of an oil field in order to provide corrective action in the studied industry and similar industries. After reviewing the issued permit to work, job description and noise dosimetry test, the evaluated areas were selected then sound pressure levels in the referenced areas investigated according to ISO 9612–2009 (E) next the noise map prepared for all selected areas. For identifying the prioritized areas to implement the control measures NCPI was used. After identifying the first priority area with sound pressure levels greater than 85 dB, the frequency analysis was performed and Isosonic map was prepared by Surfer v10 and AutoCAD 2014. In the last step, in order to provide appropriate corrective action plan, the compatibility of the determined control actions with the production process was examined. The findings of this study indicates that 74% of the aforesaid area has the first priority to perform control measures in the caution zone and the remaining 26% is in the danger zone. In this study it has been demonstrated that implementing control measures for Zone 2 have first priority. The main source of the noise in this zone is fluid (Gas) flow through the piping and HP Gas Compressors. The results of this study shows that using effective factors such as exposure time, sound pressure level and number of exposed persons, can be present suitable model to prioritize noise control.

Motion Analysis of PLET during the Setting-Down Process

The design analysis of Subsea PLET should consider various cases, including in-place analysis, lifting analysis, setting down analysis and so on. The size and vessel space should be checked in the structural design, and the fishing protection function should also be covered. The accurate setting-down process is the prerequisite for the successful construction of the subsea project. Therefore, it is necessary to simulate the various conditions included in the setting down process. Based on practical YC13-1 project and subsea environment condition, a special type of subsea PLET is designed for the pipe rehabilitation. Theoretical study is performed to discuss the load and Fluent software is used to simulate the problems encountered in the setting-down process. Comparison on the calculation results with ROV condition and without ROV condition, it indicates the effective suppression of the movement of PLET with ROV tractive action. The study can be a good reference and guidance for the design and construction of South China Sea oil and gas field project.

Clearing the Digital Minefield for Optimized Oilfield Production

The success of any digital oilfield project is predicated on the quality of the data structure, acquisition, communication, validation, storage, retrieval, and provenance of the data. Therefore, the mission of the digital oilfield architect is clear: Deliver the right data to the right users at the right time. This task is becoming more difficult because of the sheer variety of sensors, the multitude of data formats, challenges with data communication and synchronization, and the potentially large volume of data produced. While the advent of data analytics has increased the importance of designing fast and efficient data management systems, it is a multifaceted minefield to gather and process data to ensure production is optimized and risk is minimized in both conventional and unconventional operating environments.

Practical workflow to improve numerical performance in time-consuming reservoir simulation models using submodels and shorter period of time

Numerical reservoir simulation is a valuable tool to support the decision-making process in oil field projects. For this purpose, current reservoir engineering studies request numerous simulations runs for complex workflows, such as numerical reservoir characterization, data assimilation process, strategy optimisation, well placement studies, production management and supplementary project support. Thus, providing efficient and effective simulation numerical models is a critical task in reservoir simulation studies before starting the daily run demands.In this work, we propose, test and evaluate a practical workflow to improve the numerical performance of time-consuming reservoir simulation models. We provide a procedure to select representative numerical submodels and representative snapshots interval from simulation time (RSIST) to reduce the total time spent in numerical optimisation. The first approach allows the optimisation of the numerical parameters without the drawback of simulating long execution runtime. The second enables to select a range of simulation time where typical convergence problems of timestep cuts occur. The numerical parameters are then optimised using submodels and RSIST, where we highlight a workflow to reduce runtime of the optimisation of slow reservoir models. Following, the resultant set of parameters is applied to the entire (original) reservoir numerical model, improving its performance and allowing more effective execution of several simulation-runs in reservoir engineering studies.To conclude, we provide a workflow to be applied to any reservoir simulation model, especially those with complex structural grid and high-time consuming to run. Our results demonstrated remarkable improvements in the numerical performance of simulation models, with a high potential of saving days of work during probabilistic evaluations. Furthermore, we recommend this workflow as a first step before starting studies using reservoir simulation to avoid unphysical and time-demanding simulation runs that may affect future decisions.

Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

Environmental Impact Assessment of Halfaya Oilfield Project

Environmental Impact Assessment of Halfaya Oilfield Project

Analysis of return on investment in some Niger-Delta oil field projects: using the variance-gamma process

Oil field development projects face market risks, largely because the parameter of key importance, the oil price, fluctuates rapidly over time. The decision to invest or not in an oil field project is therefore very challenging, because information concerning the field is often scarce. Neither the future production, nor sales prices are known with certainly. Constraints on production level also exist, in addition to OPEC quota, which is used in this work as proxy for other production limitations. The price process that best describes the fluctuations in oil price is expected to yield better analysis with respect to expected returns (viability of the project). The Variance Gamma process which is a subordinated Lévy process effectively captures jumps in a process. Thus, Variance Gamma process and a mean reverting process are considered in the analysis. The expected revenue was found to be higher, when the variance Gamma process is used as the model for oil price. This indicates that the variance Gamma process performs better than the Ornstein-Uhlenbeck process as a model for oil price. It therefore provides a good basis for price forecasting, and optimality of investment decision.Keywords: Variance Gamma Process, Mean Reverting Process, Parameters, Niger-Delta Oil Field Projects, Expected Return, OPEC constraint

Collaborative mechanism of project profit allotment in petroleum engineering service chain with customized integration

The framework of implementing oilfield project is viewed as an engineering service chain consisting of serial different links supplied by multiple service providers in their specialized technical fields. It is the challenge for an oilfield project proprietor to ensure the consistency of accountability for quality performance of engineering services and acceptance of time limit for the project. This paper, from the view of general contractor as a group company, focuses on the tradeoff analysis of two different business strategies that are independent integration strategy and customized integration strategy, in which the factors affecting their comparative advantages are studied. The mechanism of how to distribute project profits between members of the engineering service chain is investigated. Our findings show that the optimal solution presents win-win profit distribution through the negotiation of outsourcing prices between the general contractor and multiple service providers (subcontractors) under coopetition strategy which characterizes the development trend of petroleum industry.

Mapping of natural radioactivity in soil samples of Badra oil field project using GIS program

Mapping of natural radioactivity in soil samples of Badra oil field project using GIS program

Abandonment Decision-Making of Overseas Oilfield Project Coping with Low Oil Price

The abandonment option of an operating oil project refers to the right to shut down or transfer the project. As a kind of American real option, it minimizes the impact of bad operating conditions, thus increases the initial project value. Meanwhile, as a put option, it maximizes the management flexibility in unfavorable environment, especially in the current low oil prices. This article uses the trinomial tree, rather than the binomial tree widely practiced in finance, to value the option. Its lattice structure shows flexibility and intelligibility, and improves computational efficiency and accuracy. In this article, the abandonment option value incorporates uncertainties of oil price, exchange rate, political environment and taxation policy. The risk-neutral based decisions are relatively objective for oil companies. The case study indicates that the relative relationship between the abandonment option value and the project scrap value or selling price is the key to the decision-making results. A novel conclusion from the risk-neutral prospective is that, the project is more likely to be sold at higher risk scenario or with higher profit requirement. Moreover, export duty and mineral extraction tax have a greater impact on the abandonment timing than corporate income tax. This decision-making model can be introduced with modifications to other investments with increasing risk of falling asset price.

Strategic Planning of Steam Assisted Gravity Drainage Reservoir Development under Reservoir Production and Oil Price Uncertainty

During the lifecycle of an oilfield project, well development is a critical phase due to intensive investments required for capital cost. Determining whether it is economical to develop an oilfield or not and finding the best plan for field development are the main concerns in this field of study. Drainage area development and production planning are crucial in a steam assisted gravity drainage (SAGD) project of the oil sand industry. In this study, an optimization framework for planning the development of SAGD drainage areas under uncertainty is presented. The proposed framework includes the following two major elements. First, a mixed integer optimization model is developed to arrange the multiperiod development plan of the drainage areas with consideration of capital and steam allocation restrictions. Second, uncertainties in crude oil price and reservoir production are investigated based on a multistage stochastic programming model. The results demonstrate that the method can effectively generate an e...

Beyond the Limitations of API RP-14E Erosional Velocity -A Field Study for Gas Condensate Wells

Fluid velocity has the potential to cause severe erosion damage to oil & gas production infrastructure. In order to avoid or alleviate damage due to erosion, the American Petroleum Institute Recommended Practice (API RP) 14E recommends a threshold fluid velocity for production tubing and pipelines. However, field and laboratory data have proven that the applied empirical constants, known as C-factors, within the formula are not valid for all conditions. In many cases the calculated API RP 14E erosional velocity is significantly underestimated or overestimated due to insufficient consideration of fluid characteristics. In addition, accurate field data on erosional velocity can assist proper pipe sizing calculations for prospective oilfield projects. Oversizing of tubing unnecessarily increases construction costs whilst underestimating required size of tubulars can lead to catastrophic erosion/corrosion failures. In this study new values for erosional velocity constants, beyond those suggested by API RP 14E, are proposed based on experimental data achieved from sidestream pilot test units. The experimental pilot test units were installed on four different gas condensate production fields in the south of Iran. Electrical Resistance (ER) probes were employed to gather online erosion-corrosion data from the pilot units, each of which was in service for about nine months. The results showed that higher C-factors can be safely applied for these gas condensate fields in comparison with those recommended by API RP 14E. Furthermore, it was revealed that pilot test units exposed to a higher Condensate Gas Ratio (CGR) experienced a greater rate of erosion.