The effective usage of APG surplus for oil-gas field on the example of carbon black production technology

Background. The present work is devoted to one of the key areas of research activity of the modern oil and gas scientific world: decarbonization and increasing the efficiency of the natural and associated gas usage. One of the eco-friendly ways of processing natural and associated gas is the production of carbon black (soot) from it. This method is also included in the list of best available technology (BAT). Nowadays, soot is a raw material for massive scale production of rubber products, which accounts for a large share of the manufacture of tyres, besides, carbon black is a valuable component in the paint-and-varnish and petrochemical industry (inks, plastics and many other things). The aim of the project is to assess the applicability of technologies for processing the surplus of associated petroleum gas (APG) into carbon black (CB). Materials and methods. The technology is based on the pyrolysis of hydrocarbons under the influence of high temperature with a lack of air. In the work, the following tasks were performed: CB market was studied; the analysis and choice of the optimal method for obtaining soot from APG for the N field, technological calculation, and selection of equipment and economic evaluation of the technology were performed. Results. Calculations have shown that the use of this method of APG utilization is cost-effective. The PI of the project is more than 2. Conclusion. The main advantages of this technology are: relatively low capital outlays, efficient gas utilization, reduction of carbon dioxide emissions into the atmosphere, additional income from the sale of a new product in high demand. The main disadvantage of this method of gas utilization is the lack of experience and practice of oil companies in the possibilities and methods of carbon black from APG.

Enhancing Gas Injection Compressors Performance by Lateral Thinking Resulting in 0.62 Million Barrels Oil Per Year Additional Production Capacity at Zero Cost

The Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination. Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification. Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas. One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation. This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence. Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario. This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.

Insights into Khuff Oil Rim Development in Sultanate of Oman from Extensive Drilling and Well Testing Operations

The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021. A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types. This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.

Innovative Reverse Engineering Approach in Design and Construction of New Gas Processing Facility in Brown Field Block Through Optimum Utilization of Excess Materials and Idle Equipment to Improve Capital Stewardship and Inventory Management. Case Study: Field X Associated Gas Recovery Project

Successful project management boils down to effectively and efficiently managing resources to meet the project's cost and schedule. The ability to manage project effectively becomes increasingly important to recover capital project expenditures in expiring Production Sharing Contracts (PSC) blocks. The longer the time needed for a project to complete, the higher the project capital and the lower the capital recovery. Referring to look back result of several major capital facility projects, the key challenge in meeting the project cost and schedule is related to procurement of long lead materials and key process equipment. In brown field blocks, there is an opportunity to perform reverse engineering by optimally utilizing the excess materials in the warehouse and idle/unused process equipment to solve the key challenges. As additional benefit, utilization of excess materials and idle process equipment will improve inventory management and capital stewardship, since the cost to relocate and modify the equipment are significantly lower than the cost of buying a new equipment. Field X Associated Gas Recovery Project (AGRP) provided an excellent case study of successful reverse engineering approach using excess material and idle equipment in design and construction of a new gas processing facility in brown field block. Field X AGRP is designed to recover and process associated gas from X field to be used as fuel gas for the gas turbines at the internal Power Generation Plant. However, based on lesson learned from similar opportunity in the past, the cost of construction and installation of a new gas processing facility using new construction materials and new process equipment is very high, which is uneconomic at the current oil price environment. Therefore, to make the project economic, the project team shall consider the utilization of available excess material in the warehouse and idle/unused equipment into design basis. Project team conducted assessment to several facilities across the concession area to gather equipment specification data of idle process equipment and the size of available excess materials. The gas processing facility design was reverse engineered to optimally utilize the idle process equipment and excess materials. The utilization of idle equipment and excess material in construction of the gas processing facility has successfully generated cost saving up to 5 times the project cost from avoiding purchase of new equipment and new construction materials. The project successfully recovered associated gas at the rate of 0.5 MMSCFD to be used as fuel to gas turbine and produced 60 BOPD condensate from gas-liquid separation process

Well Automation Based on Flaring

At a subsurface level, controlling uneven production and early gas breakthrough are big challenges. It is very difficult to achieve the target production while preventing unnecessary flaring from high gas to oil ratio (GOR) wells. To keep the associated gas within surface compression capacity, the High GOR wells are shut in or partially choked by production programmers through a manual work-process, which doesn't always give optimum results. PDO developed a control solution to ensure produced gas always remains within surface compression capacity while ensuring maximum production. The solution achieves this by continuously monitoring flaring and choking the high GOR wells whenever needed. It does this sequentially from highest to lowest GOR wells choking is done to an optimum level by controlling its flow line pressure above certain target. The concept revolves around automating production programmer's task and optimizing it via continuous monitoring and control in DCS, which allows wells to deliver the full potential up to the surface facility constraints with reduced operator intervention. This novel idea is to integrate subsurface and surface facility Optimization via well control. This was implemented in two of the assets in PDO where frequent flaring was identified. Both facilities have limited compression capacity and number of high GOR wells out of several Gas Oil Gravity Drainage (GOGD) producer wells. In order to achieve the goal of "Zero" flaring, the wells are choked in order from highest to lowest GOR, automatically, up to the optimum limit set by either their respective flow line pressures or to defined lower optimum limit, and optimize the production by opening the wells up to its optimum target, when there is no flare. The similar concept is now being replicated in other assets following a LEAN approach.

A Holistic Approach to Simulate the Impact of H2S on Production and Injection Surface Facilities Using an Integrated Asset Model as a Digital Twin

The presence of hydrogen sulphide (H2S) in produced reservoir fluids mandates precautions in the design and operation of the surface facilities. The toxicity and corrosive nature of H2S, and the need to prevent both plugging of reservoir formations and increasing the sulphur content of the produced oil dictates the criticality of forecasting and monitoring the volumes and concentrations of H2S flowing through the whole asset. Ensuring the concentration is within acceptable operational limits is critical to safeguard the overall asset and the integrity of the surface pipeline network. The objective of this study was to utilize a history matched Digital Twin Integrated Asset Model (IAM) to predict the volumes and concentrations of H2S in a field located offshore Abu Dhabi by modeling the multi-stage separation, H2S removal, and re-injection facilities for gas injection and gas lifts. The field consists of multiple stacked carbonate reservoirs sharing the same surface facilities. The proposed modelling of H2S removal strategy involved a series of steps beginning with the sweetening of the produced associated gas for fuel gas requirements and mixing the extracted H2S volumes with the gas injection and gas lift streams. The sweetening process effectively mitigated any potential asset integrity issues arising due to corrosion of the power generation system and other surface facility assets. The stripped H2S gas, re-combined with the remaining produced gas, was used for gas-lifts and reinjected into the lower reservoirs for pressure maintenance and enhanced oil recovery (EOR). A next-generation surface-subsurface coupled simulator was utilized for the modeling of this field including the full asset surface pipeline network, the H2S removal plant, bypass lines and re-injection facilities for gas injection and gas-lifts. The Digital Twin IAM approach provided a robust method for tracking and predicting the concentration and volume of H2S in the produced gas over a period of 50 years. The simulation allowed tracking the H2S from its initial location in the reservoirs, into the production wells, then through the pipelines, all the way to the surface facilities where the sweetening of the produced is handled. Moreover, the use of the Digital Twin allowed the verification of the disposal plan of the extracted H2S, showing that mixing it with the re-injection gas stream is a feasible option. Recommendations based on the model were provided to the production and facilities team, leading to a robust long-term field development plan that ensures asset integrity.

Estimating global oilfield-specific flaring with uncertainty using a detailed geographic database of oil and gas fields

Associated gas flaring during crude oil production is an important contributor to global warming. Satellite technology has made global flaring monitoring possible with high spatial resolution. In this study, we construct a granular database to geographically match global oil and gas fields with remote sensing flaring data from the Visible Infrared Imaging Radiometer Suite (VIIRS) from 2012 to 2019. The GIS database contains over 50,000 oil and gas fields and around 4,700 infrastructure sites (e.g., refineries, terminals) in 51 countries and regions, representing 96% of global oil production and 89% of natural gas production. Over 2,900 fields and 140 infrastructure sites in 47 countries contain matching flares. The annual matched flare volume covers 89~92% of the satellite-estimated flaring volume of these countries and 85~87% of total worldwide volume detected by the satellite. In 2019, a set of 263 “high-flare” fields (which flare more than 0.1 billion cubic meters per year) account for 67% of the total matched satellite-estimated volume. These fields are mainly concentrated in the Persian Gulf, West and East Siberia, Eastern Venezuela Basin, Permian and Williston Basins in the United States, the Gulf of Mexico, and West and North Africa. Accounting for asymmetric instrument uncertainty suggests that country-level flaring rates are accurate to within -8% ~ +29%, the global average within 1%.