Micro-Slimtube Shrinks EOR Screening From Months to a Week

2021 ◽  
Vol 73 (02) ◽  
pp. 29-31
Author(s):  
Trent Jacobs
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Flow Behavior ◽  
New Drugs ◽  
Reservoir Rock ◽  
Silicon Chips ◽  
Oil And Gas Producers ◽  
One Step ◽  
Core Flood ◽  
The Times

Oilfield testing firm Interface Fluidics says it is one step closer to reinventing the industry’s pressure-volume-temperature (PVT) testing portfolio after the development of a smaller, faster version of yet another laboratory stalwart. Representing the newest alternative to the slimtube test is the micro-slimtube test. A conventional slimtube test involves flowing gas through a sand- or glass-bead-packed metal coil that may be 1 to 4 mm wide and some 40 to 80 ft long to see how it mixes and mobilizes oil with samples also inside the tube. The test and subsequent analysis usually take a few months to complete. For a generation, this has been considered time well spent by anyone preparing to invest millions of dollars to prop up an aged asset through gas-injection-based enhanced oil recovery (EOR). But the times are changing. Interface Fluidics’ innovation, which it developed in close partnership with Equinor, measures only about 1.5 in long and generates results in about a week - about 95% sooner than the conventional bench method. The new test also reduces costs by around 75% while using a reservoir fluid sample that’s 99% smaller (10 ml vs. 1 liter). “It’s the same story over and over again - we’re miniaturizing the big stuff and putting it on a chip,” said Stuart Kinnear, CEO of Interface Fluidics. Founded in 2016, the Calgary-based firm helped introduce microfluidic technology to the oil industry with glass and silicon chips that it calls “reservoir analogues.” A well-established enabler in the healthcare industry, microfluidic devices of various stripes are routinely used to rapidly screen new drugs or to study how blood cells move through tiny veins and capillaries. In the upstream industry, Interface Fluidics is part of much smaller group of specialists proving that the devices are also ideal for screening production-enhancing chemicals and to study how oil moves about the tiny pathways of a reservoir rock (SPE 188895). The firm first showed how this works by replicating reservoir rock samples onto its chips as an alternative to core flood experiments. For oil and gas producers and their chemical providers alike (SPE 189780), the lower-cost devices made it affordable to run dozens of tests to determine how various chemistries affect flow behavior in specific geologies.

scholarly journals CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6215
Author(s):  
Manoj Kumar Valluri ◽  
Jimin Zhou ◽  
Srikanta Mishra ◽  
Kishore Mohanty
Keyword(s):  
Oil Recovery ◽  
Power Plants ◽  
Oil And Gas ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Co2 Injection ◽  
Reservoir Properties ◽  
Industrial Facilities ◽  
Water Alternating Gas ◽  
Process Understanding

Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.

Petroleum Reservoirs

1996 ◽  
Author(s):  
Craig M. Bethke
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Saline Water ◽  
Fluid Pressure ◽  
Petroleum Reservoirs ◽  
Hot Water ◽  
Reservoir Rock ◽  
Mineral Surfaces ◽  
Improved Oil Recovery ◽  
Mineral Scale

In efforts to increase and extend production from oil and gas fields, as well as to keep wells operational, petroleum engineers pump a wide variety of fluids into the subsurface. Fluids are injected into petroleum reservoirs for a number of purposes, including: • Waterflooding, where an available fresh or saline water is injected into the reservoir to displace oil toward producing wells. • Improved Oil Recovery (IOR), where a range of more exotic fluids such as steam (hot water), caustic solutions, carbon dioxide, foams, polymers, surfactants, and so on are injected to improve recovery beyond what might be obtained by waterflooding alone. • Near-well treatments, in which chemicals are injected into producing and sometimes injector wells, where they are intended to react with the reservoir rock. Well stimulation techniques such as acidization, for example, are intended to increase the formation's permeability. Alternatively, producing wells may receive “squeeze treatments” in which a mineral scale inhibitor is injected into the formation. In this case, the treatment is designed so that the inhibitor sorbs onto mineral surfaces, where it can gradually desorb into the formation water during production. • Pressure management, where fluid is injected into oil fields in order to maintain adequate fluid pressure in reservoir rocks. Calcium carbonate may precipitate as mineral scale, for example, if pressure is allowed to deteriorate, especially in fields where formation fluids are rich in Ca++ and HCO3- and CO2 fugacity is high. In each of these procedures, the injected fluid can be expected to be far from equilibrium with sediments and formation waters. As such, it is likely to react extensively once it enters the formation, causing some minerals to dissolve and others to precipitate. Hutcheon (1984) appropriately refers to this process as “artificial diagenesis,” drawing an analogy to the role of groundwater flow in the diagenesis of natural sediments (see Chapter 19). Further reaction is likely if the injected fluid breaks through to producing wells and mixes there with formation waters. There is considerable potential, therefore, for mineral scale, such as barium sulfate (see the next section), to form during these procedures.

The Effect of Compositional Gradient in Field Development

2021 ◽  
Author(s):  
Farasdaq Muchibbus Sajjad ◽  
Steven Chandra ◽  
Patrick Ivan ◽  
Wingky Suganda ◽  
Yudi Budiansah ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Flow Behavior ◽  
Cross Flow ◽  
Generalized Solution ◽  
Oil Viscosity ◽  
Compositional Gradient ◽  
Field Development ◽  
Scale Deposition ◽  
Compositional Convection

Abstract The existence of fluid’s compositional gradient in a reservoir drives convective flow which brings significant impacts to the operations, e.g., in formulation of injected fluid for well stimulation and enhanced oil Recovery (EOR). However, fluid compositional gradient is not always included in modeling reservoir performance due to PVT sampling limitation and simulation constraint. This work aims to show the significance of compositional convection in oil/gas reservoir and provides our experiences in dealing with this issue in Indonesian’s fields. PHE ONWJ as one of the most prolific producers of oil and gas in Indonesia currently operates an offshore block that has been producing for almost 40 years. Operating in a relatively mature well, PHE ONWJ often encounters significant fluid property change namely oil viscosity and specific gravity that changes overtime as depletion process occur. Data from X field, operated by PHE ONWJ, shows that compositional convection impacts workover and tertiary operations, by deviating from simulation results. We present the evidence of compositional convection using mechanistic models. We firstly adopt field data for setting the initial composition stratification. The stratification is identified through DST or fluid sampling. We secondly perform similarity simulation to analyze the effect of compositional gradient towards oil production. Similarity simulation is performed in the simplified domain for providing generalized solution. This solution is then scaled for the real domain. Finally, we show our approach to encounter the problems. Based on the similarity study inspired by the case of X Field, it shows that the compositional stratification affects geochemistry and near-wellbore flow behavior. The compositional convection develops multiple fluid properties at different depth, which create cross flow among layers. It also causes scale deposition in near wellbore which reduces the permeability and alters rock-fluid interactions, such as wettability and relative permeability. The alteration of near-wellbore geochemistry creates severe flow assurance issues in the wellbore. The mixing of multiple fluids from different layers cause paraffin and scale deposition. In some fields, the mixing triggers severe corrosions which could impact on wellbore integrity. The compositional stratification forces us to develop multiple treatments for different layers in single wellbore. Since the fluid’s properties are different for each layer, the compatibility between injected fluid and reservoir fluids varies.

Enhancing hydrocarbon productivity via wettability alteration: a review on the application of nanoparticles

2019 ◽  
Vol 35 (4) ◽  
pp. 531-563 ◽  
Author(s):  
Asefe Mousavi Moghadam ◽  
Mahsa Baghban Salehi
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Review Paper ◽  
Oil And Gas Industry ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Main Element ◽  
Preparation Methods ◽  
Hydrocarbon Production ◽  
Rock Types

AbstractWettability alteration (WA) of reservoir rock is an attractive topic in the upstream oil and gas industry, for the improvement of hydrocarbon production. Novel methods and chemicals that may change the wetting state of reservoir rock to water-wet have highly attracted petroleum researchers’ attention. Use of nanoparticles might be matured enough in different branches of sciences but in WA is still young, which increased in recent decades. This review paper presents a comprehensive review on WA, especially in terms of nanoparticle application in increasing oil recovery. Therefore, the areas of controversy of two rock types (carbonate and sandstone) as a main element in WA are discussed. A selection of reviewed nanoparticle types, preparation methods, and effective factors was also investigated. Moreover, two main methods of WA, static and dynamic, are highlighted. Although these methods have been discussed in many reviews, a clear classification form of these has not been considered. Such comprehensive arrangement is presented in this review, specifically on nanoparticle application. Moreover, coreflooding tests of different fluid types and injection scenarios are discussed. The review indicates promising use of nanoparticles in increasing ultimate oil recovery. It was hoped the current review paper can provide useful related reference to study WA via nanoparticle application.

Performance of Resins Based on Poly(Divinylbenzene-co-Methyl Methacrylate)-Based Resins for Removal of Removing Calcium and Magnesium Ions from Water

2021 ◽  
Vol 04 ◽  
Author(s):  
Camilla N. Bernardo ◽  
Carla Michele F. Silva ◽  
Paula F. Aguiar ◽  
Elizabete F. Lucas
Keyword(s):  
Methyl Methacrylate ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Cost Benefit ◽  
Reservoir Rock ◽  
Magnesium Ions ◽  
Formation Water ◽  
Injection Water ◽  
Calcium And Magnesium ◽  
Calcium And Magnesium Ions

Background: The mixing of the formation water present in oil and gas reservoirs and the injection water (often seawater) can form inorganic incrustations, during enhanced oil recovery operations. In this case, the cations (calcium, barium, strontium, iron, magnesium, etc.) of the injection water react with the anions (mainly sulfate and carbonate) of the formation water, produce Such inorganic salts can that precipitate in the reservoir rock, damaging the oil production. pipes and production lines, clogging them. One of the ways to prevent this problem is to remove the cations from the injection water, but this is a challenging procedure. Objective: In this study, the Sulfonated polymerdivinylbenzene (DVBS) and the copolymer sulfonated poly(methyl methacrylate-co-divinylbenzene (MMA-DVB) were compared in their efficiencies in reducing to a very low levels the concentration of removing chemically modified with sulfonic (S) groups to ascertain their performance in removing the calcium and magnesium ions present in water. Method: The resins were modified with sulfonic groups and characterized. We used central composition planning with batch tests to evaluate the adsorption, which occurred significantly for both ions using both resins with contact time of 10 minutes. Results: For both resins, calcium was preferentially adsorbed in relation to magnesium. Conclusion: Taking is account cost benefit, the copolymer MMA-DVBS (a less expensive adsorbent than the polymer DVBS) presented a satisfactory behavior, making it a potential material for treatment of water.

scholarly journals Flow Dynamics of Sulfate-Modified Water/Polymer Flooding in Micromodels with Modified Wettability

2020 ◽  
Vol 10 (9) ◽  
pp. 3239 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Calvin L. Gaol ◽  
Stefanie Säfken ◽  
Leonhard Ganzer
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Water Flooding ◽  
Process Efficiency ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Flood ◽  
Fluid Interaction

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems.

Recent Advances in Viscoelastic Surfactants for Improved Production From Hydrocarbon Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1340-1357 ◽  
Author(s):  
Katherine L. Hull ◽  
Mohammed Sayed ◽  
Ghaithan A. Al-Muntasheri
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Experimental Studies ◽  
Reservoir Rock ◽  
Fracturing Fluid ◽  
Improved Oil Recovery ◽  
Matrix Acidizing ◽  
Fluid Systems ◽  
Viscoelastic Surfactants

Summary Viscoelastic surfactants (VES) are used in upstream oil and gas applications, particularly hydraulic fracturing and matrix acidizing. A description of surfactant types is introduced along with a description of how they assemble into micelles, what sizes and shapes of micelles can be formed under different conditions, and finally how specific structures can lead to bulk viscoelastic-solution properties. This theoretical discussion leads into a description of the specific VES systems that have been used over the last 20 years in improved oil recovery for upstream applications. VES-based fluids have been used most extensively for hydraulic fracturing. They are preferred over conventional polymer-based fracturing-fluid systems because they are essentially solids-free systems that have demonstrated less damage to the reservoir-rock formation. In fact, approximately 10% of the fracturing treatments use VES-based fluids. Important advancements in VESs have been made by introducing “pseudocrosslinking agents,” such as nanoparticles, to enhance the viscosity. Fracturing-fluid systems modeled after VES have also been improved recently by developing internal breakers to lower their viscosity to flow back the well. The flexibility of VES-based fluids has been demonstrated by their application as foamed fluids, as well as their incorporation with brine systems such as produced water. A second key area that has benefited from VES-based systems is matrix acidizing of carbonate-based reservoirs. The viscosity of these VES-based fluids is mostly controlled by pH; at low pH (low viscosity), the acid system flows easily and invades pore spaces in the formation. During acidizing, the acid is spent, and the pH and viscosity increase. Because the spent acid has higher viscosity, fresh acid is diverted to low-permeability, uncontacted zones and penetrates the rocks to form wormholes. A number of experimental studies and field applications to these effects have been performed and will be described in this study. In order for VES-based fluids to play a more-prominent role in the field, inherent limitations such as cost, applicable temperature range, and leakoff characteristics will need to continue to be addressed. If we can efficiently and economically overcome these issues, VES-based fluids offer the industry an excellent clean and nondamaging alternative to conventional polymer-based fluids.

Main approaches to estimating the cost of shareholder equity of oil and gas producers

2020 ◽  
Vol 26 (3) ◽  
pp. 685-697
Author(s):  
O.V. Shimko
Keyword(s):  
Oil And Gas ◽  
Oil Prices ◽  
Minimum Cost ◽  
Free Cash Flow ◽  
Annual Reports ◽  
Comparative Approach ◽  
Economic Activities ◽  
Advantages And Disadvantages ◽  
Oil And Gas Producers ◽  
The Cost

Subject. The study analyzes generally accepted approaches to assessing the value of companies on the basis of financial statement data of ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, Gazprom, Rosneft, LUKOIL, and others, for 1999—2018. Objectives. The aim is to determine the specifics of using the methods of cost, DFC, and comparative approaches to assessing the value of share capital of oil and gas companies. Methods. The study employs methods of statistical analysis and generalization of materials of scientific articles and official annual reports on the results of financial and economic activities of the largest public oil and gas corporations. Results. Based on the results of a comprehensive analysis, I identified advantages and disadvantages of standard approaches to assessing the value of oil and gas producers. Conclusions. The paper describes pros and cons of the said approaches. For instance, the cost approach is acceptable for assessing the minimum cost of small companies in the industry. The DFC-based approach complicates the reliability of medium-term forecasts for oil prices due to fluctuations in oil prices inherent in the industry, on which the net profit and free cash flow of companies depend to a large extent. The comparative approach enables to quickly determine the range of possible value of the corporation based on transactions data and current market situation.

Financial and Economic Support of Innovation Processes in the Russian Fuel and Energy Complex

2019 ◽  
Vol 12 (3) ◽  
pp. 77-85
Author(s):  
L. D. Kapranova ◽  
T. V. Pogodina
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Oil And Gas ◽  
New Technologies ◽  
Innovative Development ◽  
Oil Reserves ◽  
Energy Complex ◽  
Innovation Activities ◽  
Substantial Investment ◽  
The Government

The subject of the research is the current state of the fuel and energy complex (FEC) that ensures generation of a significant part of the budget and the innovative development of the economy.The purpose of the research was to establish priority directions for the development of the FEC sectors based on a comprehensive analysis of their innovative and investment activities. The dynamics of investment in the fuel and energy sector are considered. It is noted that large-scale modernization of the fuel and energy complex requires substantial investment and support from the government. The results of the government programs of corporate innovative development are analyzed. The results of the research identified innovative development priorities in the power, oil, gas and coal sectors of the fuel and energy complex. The most promising areas of innovative development in the oil and gas sector are the technologies of enhanced oil recovery; the development of hard-to-recover oil reserves; the production of liquefied natural gas and its transportation. In the power sector, the prospective areas are activities aimed at improving the performance reliability of the national energy systems and the introduction of digital technologies. Based on the research findings, it is concluded that the innovation activities in the fuel and energy complex primarily include the development of new technologies, modernization of the FEC technical base; adoption of state-of-the-art methods of coal mining and oil recovery; creating favorable economic conditions for industrial extraction of hard-to-recover reserves; transition to carbon-free fuel sources and energy carriers that can reduce energy consumption and cost as well as reducing the negative FEC impact on the environment.

ASSESSMENT OF OIL WELL PRODUCTIVITY IN LOW-PERMEABILITY RESERVOIRS IN THE FIELDS OF EASTERN SIBERIA

2017 ◽  
pp. 30-36
Author(s):  
R. V. Urvantsev ◽  
S. E. Cheban
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Oil And Gas ◽  
Oil Extraction ◽  
Low Permeability ◽  
Oil Well ◽  
Eastern Siberia ◽  
Development Costs ◽  
Traditional Fields ◽  
Low Permeability Reservoirs

The 21st century witnessed the development of the oil extraction industry in Russia due to the intensifica- tion of its production at the existing traditional fields of Western Siberia, the Volga region and other oil-extracting regions, and due discovering new oil and gas provinces. At that time the path to the development of fields in Eastern Siberia was already paved. The large-scale discoveries of a number of fields made here in the 70s-80s of the 20th century are only being developed now. The process of development itself is rather slow in view of a number of reasons. Create a problem of high cost value of oil extraction in the region. One of the major tasks is obtaining the maximum oil recovery factor while reducing the development costs. The carbonate layer lying within the Katangsky suite is low-permeability, and its inventories are categorised as hard to recover. Now, the object is at a stage of trial development,which foregrounds researches on selecting the effective methods of oil extraction.

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