Relationship between oil production and CO2 storage during low-salinity carbonate water injection in acid carbonate reservoirs

There are currently two fiscal regimes designated for resource allocation in Indonesia’s upstream oil and gas industry, the Production Sharing Contract Cost Recovery (PSC) and Gross Split. The Gross Split in the form of additional percentage split is designed to encourage contractors to implement Enhanced Oil Recovery (EOR) in mature fields. Low Salinity Water Injection (LSWI) is an emerging EOR technique in which the salinity of the injected water is controlled. It has been proven to be relatively cheaper and has simpler implementations than other EOR options in several countries. This study evaluates the LSWI project’s economy using PSC and Gross Split and then to be compared to conventional waterflooding (WF) project’s economy. There are four cases on Field X that are simulated using a commercial simulator for 5 years. The cases are evaluated under PSC and Gross Split to calculate the project’s economy. The economic indicators that will be evaluated are the Net Present Value (NPV) and sensitivity analysis is also conducted to observe the change of NPV. The parameters for sensitivity analysis are Capital Expenditure (CAPEX), Operating Expenditure (OPEX), Oil Production, and Oil Price. It is found that LSWI implementation using Gross Split is more profitable than PSC. The parameters that affects NPV the most in all PSC cases are the oil production and oil price. On the other hand, in Gross Split cases, the oil production is the parameter that affects NPV the most, followed by oil price. The novelty of this study is in the comparison of project’s economy between WF and LSWI using two different fiscal regimes to see whether Gross Split is more profitable than PSC on EOR implementation, specifically the LSWI at Field X.

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New Insights into the Low Salinity Water Injection Effect on Oil Recovery from Carbonate Reservoirs

10.2523/iptc-17244-ms ◽

2014 ◽

Cited By ~ 5

Author(s):

Emad W. Al Shalabi ◽

Kamy Sepehrnoori ◽

Mojdeh Delshad

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Carbonate Reservoirs ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Injection Effect ◽

Low Salinity Water Injection

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Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

Journal of Chemistry ◽

10.1155/2017/8142032 ◽

2017 ◽

Vol 2017 ◽

pp. 1-10 ◽

Cited By ~ 1

Author(s):

Ji Ho Lee ◽

Kun Sang Lee

Keyword(s):

Oil Recovery ◽

Saline Water ◽

Water Injection ◽

Carbonate Reservoirs ◽

Viscosity Reduction ◽

Low Salinity ◽

Low Salinity Water ◽

Geochemical Reactions ◽

Salinity Water ◽

Low Salinity Water Injection

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

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Impact of injected water salinity on CO2 storage efficiency in homogenous reservoirs

The APPEA Journal ◽

10.1071/aj17041 ◽

2018 ◽

Vol 58 (1) ◽

pp. 44 ◽

Cited By ~ 5

Author(s):

Emad A. Al-Khdheeawi ◽

Stephanie Vialle ◽

Ahmed Barifcani ◽

Mohammad Sarmadivaleh ◽

Stefan Iglauer

Keyword(s):

Co2 Storage ◽

Water Injection ◽

Water Salinity ◽

Co2 Injection ◽

Storage Efficiency ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Low Salinity Water Injection ◽

Wag Injection

Water alternating gas (WAG) injection significantly improves enhanced oil recovery efficiency by improving the sweep efficiency. However, the impact of injected water salinity during WAG injection on CO2 storage efficiency has not been previously demonstrated. Thus, a 3D reservoir model has been developed for simulating CO2 injection and storage processes in homogeneous reservoirs with different water injection scenarios (i.e. low salinity water injection (1000 ppm NaCl), high salinity water injection (250 000 ppm NaCl) and no water injection), and the associated reservoir-scale CO2 plume dynamics and CO2 dissolution have been predicted. Furthermore, in this work, we have investigated the efficiency of dissolution trapping with and without WAG injection. For all water injection scenarios, 5000 kton of CO2 were injected during a 10-year CO2 injection period. For high and low salinity water injection scenarios, 5 cycles of CO2 injection (each cycle is one year) at a rate of 1000 kton/year were carried out, and each CO2 cycle was followed by a one year water injection at a rate of 0.015 pore volume per year. This injection period was followed by a 500-year post injection (storage) period. Our results clearly indicate that injected water salinity has a significant impact on the quantity of dissolved CO2 and on the CO2 plume dynamics. The low salinity water injection resulted in the maximum CO2 dissolution and minimum vertical migration of CO2. Also, our results show that WAG injection enhances dissolution trapping and reduces CO2 leakage risk for both injected water salinities. Thus, we conclude that the low salinity water injection improves CO2 storage efficiency.

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Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽

10.2118/172183-pa ◽

2015 ◽

Vol 20 (03) ◽

pp. 483-495 ◽

Cited By ~ 18

Author(s):

M. A. Mahmoud ◽

K. Z. Abdelgawad

Keyword(s):

Zeta Potential ◽

Oil Recovery ◽

Chelating Agents ◽

Water Injection ◽

Chelating Agent ◽

Carbonate Reservoirs ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water ◽

Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

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