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.

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.

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.

Nanoparticles Aid Oil Recovery During Alternating Injection

2021 ◽  
Vol 73 (09) ◽  
pp. 62-63
Author(s):  
Chris Carpenter
Keyword(s):  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Surfactant Solution ◽  
Volatile Oil ◽  
Technical Conference ◽  
Reservoir Rock ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Custom Made ◽  
Salinity Water

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201586, “Effect of Silica Nanoparticles on Oil Recovery During Alternating Injection With Low-Salinity Water and Surfactant Into Carbonate Reservoirs,” by Saheed Olawale Olayiwola, SPE, and Morteza Dejam, SPE, University of Wyoming, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Although the potential of nanoparticles (NPs) to improve oil recovery is promising, their effect during alternating injection is still uncertain. The main objective of the authors’ study is to investigate the best recovery mechanisms during alternating injection of NPs, low-salinity water (LSW), and surfactant and transform the results into field-scale technology. The outcome of these experiments revealed that tertiary injection of NPs results in additional oil recovery beyond the limits of LSW. Introduction A series of coreflooding experiments was conducted using several cores with an effective permeability of approximately 1 md to the brine at a temperature and pressure of 70°C and 3,000 psi. The study performs four different alternating injections of NPs with LSW and surfactant to determine optimal oil recovery. The wettability of the rock and fluid and the interfacial tension (IFT) of oil and water are measured to understand the mechanisms of interactions between the fluids and the reservoir rock. Materials A 12×12×12-in. block taken from an outcrop of Indiana limestone reservoir was purchased for this study. Four core plugs with a diameter of 1.5 in., used for the coreflooding experiments, were selected from this block. A synthetic 100,000-ppm (10 wt%) brine was prepared in the laboratory by dissolving sodium chloride (NaCl) and calcium chloride with a ratio of 4:1 in deionized water. The crude oil used in this study was a volatile oil (properties are described in Table 2 of the complete paper) obtained from the Permian Basin in Texas. Injected Fluids. A 10,000-ppm (1 wt%) LSW was prepared by diluting the synthetic brine 10 times. The surfactant solutions were prepared from an anionic sodium dodecyl sulfate (SDS) surfactant. A 1,000-ppm (0.1 wt%) surfactant solution used throughout the experiments was selected on the basis of the estimated critical micelle concentration of 600 to 2,240 ppm for SDS and nanofluid/NaCl. The concentration of silica NPs used in this study was 500 ppm (0.05 wt%). The nanofluids were pre-pared either as a simple solution or as a mixture with other chemicals to make a concentration of 500-ppm silica NPs. Coreflooding System. The established coreflooding system used for this experimental study was custom-made to determine the oil recovery and the relative permeabilities at steady-state and unsteady-state flows. However, the focus of this study is to investigate the effect of silica NPs on oil recovery. The schematic diagram of the coreflooding system is shown in Fig. 1.

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

Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Yang Zhao ◽  
Shize Yin ◽  
Randall S. Seright ◽  
Samson Ning ◽  
Yin Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Salinity ◽  
Polymer Flooding ◽  
Heavy Oil Recovery ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Increased Oil Recovery

Summary Combining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing 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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