Novel Dual-Tubing Technique to Eliminate the Shut-in Period in CO2 Huff-n-Puff Injection for Heavy Oil Carbonate Reservoirs

2021 ◽  
Author(s):  
Zakaria Hamdi ◽  
Nirmal Mohanadas ◽  
Margarita Lilaysromant ◽  
Oluwole Talabi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Injection Rate ◽  
Co2 Injection ◽  
Base Case ◽  
Production Time ◽  
Novel Approach ◽  
Dual Porosity Model ◽  
Carbon Dioxide Co2 ◽  
First Time

Abstract Some heavy oil production can be established using conventional methods; however, these methods are often somewhat ineffective with low recovery factors of less than 20%. Carbon dioxide (CO2) huff-n-puff or cyclic CO2 injection is one of the Enhanced oil recovery (EOR) methods that can be used in stimulating aging wells to recover some residual oil. The shut-in stage of this method results in a significant delay in the production time, and hence lower oil recovery. For the first time, in this paper, an attempt is made to overcome this issue by a novel approach, employing dual tubing completions. The aim of this is to increase the oil recovery with the production during soak time. Also, a majority of the remaining heavy oil reservoirs are carbonates, hence the research was focused on the same conditions. Numerical simulation is done using dual-tubing conditions in a dual-porosity model with conventional tubing as a base case. Optimization studies are done for injection rate, injection time, soaking time, production time, and huff-n-puff cycles. The results show that the recovery factor can increase significantly, with no discontinuity in production. Preliminary economic studies for the cases also showed a net increase in profit of 7% (1.3 million Dollars for the case chosen). This demonstrates the feasibility of the proposed method which can be implemented into conventional operations, for a more sustainable economy in the era of low oil prices.

scholarly journals Enhancement of Heavy Oil Recovery with High CO2 Injection Rates in Silica Nanochannel

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Shuo Zhang ◽  
Yanyu Zhang ◽  
Xiaofei Sun
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Adsorption ◽  
Injection Rate ◽  
Design Guidelines ◽  
Nonequilibrium Molecular Dynamics ◽  
Co2 Injection ◽  
Heavy Oil Recovery ◽  
Co2 Gas ◽  
Dynamics Simulations

Abstract CO2 injection enhanced oil recovery has become one of the most important approaches to develop heavy oil from reservoirs. However, the microscopic displacement behavior of heavy oil in the nanochannel is still not fully understood. In this paper, we use CO2 as the displacing agent to investigate the displacement of heavy oil molecules confined between the hydroxylated silica nanochannel by nonequilibrium molecular dynamics simulations. We find that for heavy oil molecules, it requires more much higher displacing speed to fully dissipate the residual oil which is found related to the decreased CO2 adsorption on the silica nanochannel. A faster CO2 gas injection rate will lower the CO2 adsorption inside the nanochannel, and more CO2 will participate in the displacement of the heavy oil. The results from this work will enhance our understanding of the CO2 gas displacing heavy oil recovery and design guidelines for heavy oil recovery applications.

Low-Salinity Water, CO2, Alkaline, and Surfactant EOR Methods Applied to Heavy Oil in Sandstone Cores

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1729-1744
Author(s):  
Hasan N. Al-Saedi ◽  
Ralph E. Flori ◽  
Soura K. Al-Jaberi ◽  
Waleed Al-Bazzaz
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Sodium Dodecyl ◽  
Alkaline Treatment ◽  
Co2 Injection ◽  
Low Salinity ◽  
Water Alternating Gas ◽  
Average Improvement ◽  
Carbon Dioxide Co2 ◽  
Foam Flooding

Summary Generally, injecting carbon dioxide (CO2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO2; WAG with CO2 and FW and/or LSW; foam flooding by adding a surfactant with CO2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (ϕ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a “recipe” of EOR methods in combination that uses alkaline, LSW, surfactant, and CO2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline + LSW spacer + surfactant + CO2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. ERRATUM NOTICE:An erratum has been added to this paper detailing addition of an omitted reference.

Evaluating the Effects of CO2 Injection in Faulted Oil Reservoirs

2014 ◽  
Author(s):  
A.. Augustus ◽  
D.. Alexander
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Geologic Sequestration ◽  
Sweep Efficiency ◽  
Fracture Pressure ◽  
Carbon Dioxide Co2 ◽  
Migration Pathways

Abstract The geologic sequestration of carbon dioxide (GCS) into depleted reservoirs has been contemplated and tested in several projects globally both for permanent storage of carbon dioxide (CO2) and enhancing oil recovery (EOR). Utilization of geologic sequestration as a mitigation strategy to reduce the effects of anthropogenic CO2 into the atmosphere may be costly without proper incentives. This cost can be lowered when incremental oil is recovered in mature fields because of rising oil prices and possibly earning carbon credits for sequestered CO2. The injection of CO2, for most of the infrastructure should be in place for mature fields. Therefore many EOR coupled with CO2 sequestration projects attempt to maximize the recovery of oil whilst storing as much CO2 as possible. Many oil reservoirs are reaching or have reached their maturity therefore secondary and tertiary methods for EOR have become increasingly important for sustainable volumes of oil to be produced. Reservoir simulators have become increasingly important in the pre-evaluation of these projects for proper reservoir management and evaluation. One of the most critical problems when considering the geologic storage of CO2 is the risk of leakage which can lead to seepage from the storage area. In Trinidad and Tobago (T&T) many reservoirs are highly faulted. Some faults form an integral part of the structural traps whilst others are leaky and provide migration pathways for the injected CO2 to return to surface. A simulation study was conducted using the commercial compositional simulator CMG-GEM. The model described in this paper seeks to optimize the injection of CO2 into an oil reservoir with some degree of compartmentalization due to faulting whilst maximizing the amount of incremental oil that can be produced. One of the main considerations will be to maximize the sweep efficiency below the fracture pressure and fault entry pressure. The model is intended for a type of formation likely to be used for storage in Trinidad. We conducted sensitivity analysis on the injection rate and fault transmissibity in an analogous field to those located offshore Trinidad. It was concluded that faults transmissibility affect the overall production of oil reservoirs. Sealing faults stored less CO2 and had less cumulative production than non sealing faults.

scholarly journals Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7676
Author(s):  
Ilyas Khurshid ◽  
Imran Afgan
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Injection Rate ◽  
Rock Properties ◽  
Co2 Injection ◽  
Formation Damage ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs ◽  
Carbon Dioxide Co2 ◽  
Injection Rates

The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

2021 ◽  
Vol 73 (06) ◽  
pp. 65-66
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Improved Oil Recovery ◽  
Midland Basin ◽  
The North ◽  
Production Wells ◽  
Original Oil In Place ◽  
Carbon Dioxide Co2

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

Enhanced Heavy Oil Recovery by Intermittent CO2 Injection

2015 ◽  
Author(s):  
S. Mehdi Seyyedsar ◽  
S. Amir Farzaneh ◽  
Mehran Sohrabi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Injection ◽  
Heavy Oil Recovery

Extraction of Dissolved Methane in Brines by CO2 Injection: Implication for CO2 Sequestration

2010 ◽  
Vol 13 (05) ◽  
pp. 791-804 ◽  
Author(s):  
Ian Taggart
Keyword(s):  
Oil Recovery ◽  
Co2 Sequestration ◽  
Co2 Injection ◽  
Dissolved Gas ◽  
Long Term Storage ◽  
Two Component ◽  
Component Solubility ◽  
Carbon Dioxide Co2 ◽  
Term Storage

Summary The solubility of carbon dioxide (CO2) in underground saline formations is considered to offer significant long-term storage capability to effectively sequester large amounts of anthropogenic CO2. Unlike enhanced oil recovery (EOR), geosequestration relies on longer time scales and involves significantly greater volumes of CO2. Many geosequestration studies assume that the initial brine state is one containing no dissolved hydrocarbons and, therefore, apply simplistic two-component solubility models starting from a zero dissolved-gas state. Many brine formations near hydrocarbons, however, tend to be close to saturation by methane (CH4). The introduction of excess CO2 in such systems results in an extraction of the CH4 into the CO2-rich phase, which, in turn, has implications for monitoring of any sequestration project and offers the possibly additional CH4 mobilization and recovery.

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