The geosolitonic concept of high output hydrocarbon deposits formation

Based on the well-known results of studies of the ether-geosoliton concept of the growing Earth, the article presents the conclusions that made it possible to propose a model of thermonuclear synthesis of chemical elements that form renewable reserves of developed oil and gas fields. It was revealed that local zones of abnormally high production rates of production wells and, accordingly, large cumulative production at developed fields in Western Siberia are due to the restoration of recoverable reserves due to geosoliton degassing. Therefore, when interpreting the results of geological and geophysical studies, it is necessary to pay attention to the identified geosoliton degassing channels, since in the works of R. M. Bembel and others found that they contributed to the formation of a number of hydrocarbon deposits in Western Siberia. When interpreting the results of geological-geophysical and physicochemical studies of the fields being developed, it is recommended to study the data of the ring high-resolution seismic exploration technology in order to identify unique areas of renewable reserves, which can significantly increase the component yield of hydrocarbon deposits.

Organic Oil Recovery - Resident Microbial Enhanced Production Pilot in Bahrain

Tatweer Petroleum has been involved in a Pilot study to determine the efficacy of Organic Oil Recovery (OOR), a unique form of microbial enhanced oil recovery as a means of maximising oil recovery from its Rubble reservoir within the Awali field. OOR harnesses microbial life already present in an oil-bearing reservoir to improve oil recovery through changes in interfacial tensions, which in the case of Rubble will increase the heavy oil's mobility and improve recovery rates and reservoir wettability. These changes could increase recoverable reserves and extend field life through improved oil recovery with negligible topsides modifications. The Pilot injection is implemented by injecting a specific nutrient blend directly at the wellhead with ordinary pumping equipment. The well is then shut-in for an incubation period and thereafter returned to production. In Tatweer Petroleum's Awali field the Rubble reservoir is one of the shallowest oil reservoirs in the Bahrain and the first oil discovery in the Gulf Cooperation Council (GCC) region. The reservoir can be found at depths of around 1400 – 1900 ft. During initial laboratory testing of the Rubble target wells the reservoir showed a diverse and abundant resident ecology which has been proven capable of undergoing the necessary characteristic changes to facilitate enhanced production from the target wells. The Pilot test on one of these wells, called Well (A) within this paper, took place in July 2020 and due to this process, the ecology of this well showed these same changes in characteristics in the reservoir along with an associated oil response. The full method of implementation of the Pilot test will also be discussed in detail and will include any challenges and/or successes in this area. The initial state ecology reports of Well (A) are demonstrated and compared to that of post-Pilot test ecology. We also present the production figures for the well prior to and post the Pilot implementation. A correlation will be demonstrated between changes in ecology and an increase in production.

Reservoir to Tank: Fit for Purpose Integrated Workflows for Waterflood Management and Production Enhancement

Integrated solutions are important to formulate plans for mature reservoirs under waterflooding due to related dynamic changes and uncertainties. The reservoir and field management need to be handled as an integrated system, and therefore needing a multidisciplinary approach. This paper demonstrates how the integrated multidisciplinary team has developed several workflows covering water-flooding management, production enhancement and maximizing the economic recovery of reservoirs in the North Kuwait asset. Many integrated workflows were developed for water flooding and production optimization. The main integrated workflows that were implemented are as follows: PVT Properties Tool: is designed to estimate the fluid properties throughout the reservoir taking into consideration areal and vertical variations based on trends, and existing data coverage. Opportunity Maps: is a combination of updated reservoir pressure and fluids properties to provide a fast way to identify areas of opportunity to increase/decrease injection or production based on the development strategy. Waterflooding Patterns/segments Review Workflow and Allowable Tool: This integrated analytical workflow applied on predefined reservoir patterns or segments based on geological distribution and/or hydraulic communication, includes several tools like the analysis of production and injection trends, diagnostic plots to assess good vs bad water, Hall plots, Reservoir Pressure data, tracer data, salinity changes and pump intake pressure trends. Geological analysis (cross-sections, well correlations, sand thickness maps) for each layer are integrated in each pattern/segment review to support reservoir connectivity (or the lack thereof). Instantaneous and cumulative VRR are calculated and compared with the overall exploitation strategy and water injection efficiency. Other sub-workflows were developed to improve and manage waterflooding performance such as water recirculation tool and streamline sector modeling simulation. Structured integrated proactive production and ESP optimization workflows: Production optimization is a continuous iterative process (cycles) to improve production, especially in mature fields. This workflow facilitates the identification of opportunities for production optimization with a pro-active approach focusing on flowing wells and rig-less interventions to tackle production challenges and achieve production targets. The Heterogeneity Index (HI) process is utilized to rapidly demonstrate production gain opportunities. This provides family-type problems that are then represented by type-wells for detailed diagnostics. Continuous application and embedding of such structured integrated workflows as standard best practices, deliver significant value in terms of improving the understanding of reservoir performance in order to inject smart (where and when required) and produce smart (sweet healthy spots). This is done on reservoir, segment, pattern and individual well levels in multidisciplinary team domains. The ultimate results reflected in continuous improvement in waterflooding management (injection efficiency, vertical and areal sweep efficiency, sweep new oil via changing streamlines). This in turn contributes to significant added oil gain and recoverable reserves with best practices reservoir management. These integrated workflows are user friendly and can be applied across different reservoirs and fields. The application of such workflows in a structured, consistent and proactive approach improves the overall asset management in terms of maximizing production and recoverable reserves.

The rejuvenations of hydrocarbon exploration in the Eastern Mediterranean

The exploration history of the large East Mediterranean Basin, which encompasses the Nile delta, Levantine, Herodotus and Eratosthenes provinces, has seen several phases of rejuvenation since exploration started in the 1950s, with new plays opened repeatedly after the basin was considered mature by the industry. The 584 exploration wells drilled to date have discovered more than 23 Bboe recoverable reserves/resources, mostly gas. The first discovery was the Abu Madi Field, in 1967, which opened the Messinian clastic play. Over time, other plays and sub plays were opened, including the Serravallian-Tortonian, the Plio-Pleistocene, the Oligo/Miocene in the Levantine, the intra Oligocene and the Cretaceous carbonates (Zohr discovery, 2015). The exceptional variety of plays, with different trapping styles, reservoir and seal facies patterns has few equivalents worldwide and makes the region a valuable training ground for explorers. The geological variety is not the only reason for such a complex and episodic exploration history: commercial (gas market) and geopolitical issues have also had an impact on the activity in parts of the basin. The largest discoveries have been made in the last 10 years (Tamar, Leviathan, Zohr) and, despite the intense exploration activity, parts of the basin remain underexplored. The company with the longest and most successful play opening history in the basin is Eni. Today, most major oil companies are active in the basin, which even after 70 years is still considered one of the world's exploration hotspots.

Increase in recoverable oil reserves based on system treatments of injection wells

Background. The article considers and justifies the need to take into account the indicators that characterize the amount of balance reserves involved in the development, as well as the increase in recoverable oil reserves due to EOR, when evaluating the technological efficiency of the treatment of the alignment of the pick-up profile (RUNWAY). Aim. If the increase in recoverable reserves is significantly less than production, this will lead to a loss of oil production potential. This fact is of particular importance in the conditions of the arrangement of the old squares and the presence of a developed infrastructure on them. Materials and methods. Materials were used to assess the dynamics and degree of development of oil reserves, calculations of the increase in recoverable reserves. Results. The article presents the results of the accumulated technological efficiency of work to improve oil recovery using various technologies for leveling the intake profile (runway) and non-stationary flooding at the facilities of Subsurface user in Khanty-Mansi Autonomous Area – Yugra on the basis of system-targeted impact on the reservoir. The article also presents materials on the assessment of the dynamics and degree of development of oil reserves, as well as calculations of the increase in recoverable reserves. Conclusions. Calculations based on the assessment of the increase in initial and residual recoverable oil reserves from the implementation of annual EOR programs carried out in accordance with the methodology of PJSC Gazpromneft indicate that the implementation of these programs contributes to additional involvement in the active development of previously poorly drained or non-drained oil reserves.

Derivation of water flooding characteristic curve for offshore low-amplitude structural reservoir with strong bottom water

The water flooding characteristic curve method is one of the essential techniques to predict recoverable reserves. However, the recoverable reserves indicated by the existing water flooding characteristic curves of low-amplitude reservoirs with strong bottom water increase gradually, and the current local recovery degree of some areas has exceeded the predicted recovery rate. The applicability of the existing water flooding characteristic curves in low-amplitude reservoirs with strong bottom water is lacking, which affects the accurate prediction of development performance. By analyzing the derivation process of the conventional water flooding characteristic curve method, this manuscript finds out the reasons for the poor applicability of the existing water flooding characteristic curve in low-amplitude reservoir with strong bottom water and corrects the existing water flooding characteristic curve according to the actual situation of the oilfield and obtains the improvement method of water flooding characteristic curve in low-amplitude reservoir with strong bottom water. After correction, the correlation coefficient between $$\frac{{k_{ro} }}{{k_{rw} }}$$ k ro k rw and $$S_{w}$$ S w is 95.92%. According to the comparison between the actual data and the calculated data, in 2021/3, the actual water cut is 97.29%, the water cut predicted by the formula is 97.27%, the actual cumulative oil production is 31.19 × 104t, and the predicted cumulative oil production is 31.31 × 104t. The predicted value is consistent with the actual value. It provides a more reliable method for predicting low-amplitude reservoirs' recoverable ability with strong bottom water and guides the oilfield's subsequent decision-making.

Subsurface Compressor System Improves Gas Production in Unconventional Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201138, “Liquid Removal To Improve Gas Production and Recoverable Reserves in Unconventional Liquid-Rich Reservoirs by Subsurface Wet Gas Compression,” by Lukas Nader, SPE, David Biddick, SPE, and Herman Artinian, SPE, Upwing Energy, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition—Americas, 10–12 November. The paper has not been peer reviewed. This paper describes an artificial lift technology, a subsurface compressor system (SCS), that simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The first field trial of the technology in an unconventional shale gas well supports the mechanism of subsurface gas compression and its benefit to unconventional gas production. The SCS This paper focuses on the latest deployed design. As with all SCS systems, this unit has three major components (Fig. 1). High-Speed Motor. The motor is a four-pole, high-speed, permanent-magnet (PM) synchronous topology. The motor maximum operating speed is 50,000 rev/min, with a 55,000-rev/min overspeed. Surface-mounted PMs are retained on the shaft surface. A sine filter is also used to minimize harmonic losses in the rotor, eliminating the need for active cooling flow in the rotor cavity. With the motor housing hermetically sealed from the environment and maintaining a low pressure within the housing, a minimum life of 20 years is expected from the electrical motor section. The motor rotor is levitated with passive magnetic bearings, requiring no lubrication or a pressurized air source, to support the high-speed rotating shafts. Magnetic Coupling. The magnetic coupling consists of three major components: the male and female ends of the magnetic coupling as well as the isolation can in between. The female end of the magnetic coupling is attached directly to the motor. The isolation can is used to seal the female magnetic coupling section hermetically within the body of the PM motor from the environment. Using a magnetic coupling to transmit torque through an isolation can is one of the key features of the protectorless, rotating, sealless motor system to ensure reliability of the motor. Hybrid Wet Gas Compressor. The compressor is a multistage hybrid axial flow wet compressor. The key advantage of this proprietary compressor design is its relatively straight flow path compared with those of centrifugal compressors. When the flow path is straight, with little change of direction, the heavier constituents, including liquids and solids, will follow the gas phase because there is little or no centrifugal force to separate the high-density phases from the low-density one. Also, erosion of the compressor parts is minimized by the straight flow pattern because of the lower probability of impingements of solid particles on the compressor internal surfaces compared with the torturous internal paths of centrifugal compressors. The remainder of the system, as well as the deployment, is very similar to an electrical submersible pump.

Automation of the forecasting process for wells base production

The article describes the automation of the production forecast calculation method for producing wells. Calculation for each well based on monthly production report data and current residual recoverable reserves. The Arps curve and the Corey function are used to approximate the actual production curves. Comparative analysis of actual data with retro-forecast data showed high accuracy with a short calculation time.

ESPCP - An Economic Artificial Lift Method for an Offshore Field in Southwest Trinidad

Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad. In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance. The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves. Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.

Modeling Evaluates CO2 EOR, Storage Potential in Depleted Reservoirs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200560, “CO2-EOR and Storage Potentials in Depleted Reservoirs in the Norwegian Continental Shelf,” by Elhans Imanovs, SPE, and Samuel Krevor, SPE, Imperial College London, and Ali Mojaddam Zadeh, Equinor, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 8–11 June. The paper has not been peer reviewed. A combination of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage schemes could offer an opportunity to produce additional oil from depleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. The complete paper evaluates the effect of different injection methods on oil recovery and CO2 storage potential in a depleted sandstone reservoir in the Norwegian Continental Shelf (NCS). The methods include continuous gas injection (CGI), continuous water injection (CWI), water alternating gas (WAG), tapered WAG (TWAG), simultaneous water above gas coinjection (SWGCO), simultaneous water and gas injection (SWGI), and cyclic SWGI. CO2 EOR and Storage in the NCS In recent years, the number of newly explored fields in the NCS has decreased. Approximately 47% of total resources in the NCS have been produced, and approximately 20% of resources are estimated as recoverable reserves. To fill in the gap between energy demand and recoverable reserves, EOR methods could be employed. One of the most efficient EOR methods is CO2 injection, because complete microscopic sweep efficiency can be achieved, leading to a total depletion of the reservoir. The three major types of CO2 EOR processes—miscible, near-miscible, and immiscible—are described and discussed in the full paper. Four primary CO2-trapping mechanisms are used in the subsurface: structural/stratigraphic, solubility, residual, and mineral trapping. The main locations for underground geological storage are depleted oil and gas reservoirs, coal formations, and saline aquifers. Currently, underground CO2 storage is believed to be a major technology to dramatically reduce CO2 amounts in the atmosphere. According to the International Energy Agency, 54 major oil basins around the world have the potential to produce 75 Bsm3 of additional oil and store 140 Gt of CO2. CO2 EOR and storage projects in the NCS could have several benefits. First, surface and subsea facility availability in the NCS region reduces capital expenditures. Second, in addition to the revenue from extra oil production, carbon credits could be awarded for the CO2 storage. The main challenges of CO2 EOR and storage offshore projects are high operational and capital expenditures. In depleted reservoirs, these include modification of offshore platform materials; additional power supply for CO2 compression and recycling; and replacement of the tubing because wet CO2 is highly corrosive, resulting in scale, asphaltene, and hydrates formation. Contamination of a gas cap with injected CO2 might lead to loss of hydrocarbon gas market value. Only one CO2 EOR project has been implemented offshore—the Lula field in Brazil’s Santos Basin—meaning that industry has very limited experience in such projects.