Low Permeability Gas Reservoirs and Formation Damage -Tricks and Traps

Bennion, D.B.; Thomas, F.B.; İmer, Derya Y.; Ma, T.

doi:10.2118/59753-ms

Cited by 32 publications

(9 citation statements)

References 11 publications

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“…The core was then flooded with a mixture of 75% n-decane (nC 10 ) and 25% n-hexadecane (nC 16 ) to displace the liquid remaining in the core, followed with isopropyl alcohol (IPA) to clean out adsorbed chemicals. However, the continuously decreased permeability indicates that the chemical solutions did not solve the problem.…”

Section: Verendrye Core #23mentioning

confidence: 99%

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Productivity Improvement in the Viking Reservoirs of West-Central Saskatchewan

Sayegh

Luo

Zhang

et al. 2009

Canadian International Petroleum Conference

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The Viking reservoirs of west-central Saskatchewan contain a large number of light oil resources, of which only approximately 10% is considered recoverable. Oil production is hindered by (a) permeability damage due to clay swelling and migration during water injection and (b) organic solid (asphaltenes/wax) precipitation due to pressure and temperature variations. The Saskatchewan Research Council conducted laboratory experiments to evaluate and address these problems. Reservoir cores were tested for permeability damage measurements using both injection and produced brine. Different additives [i.e., potassium chloride (KCl) with/without hydrochloric acid (HCl), commercial clay stabilizers, liquid CO 2 , and isopropyl alcohol] were assessed as permeability remedies. The results showed that injection brine caused greater permeability damage than produced brine. KCl solutions preserved permeability, whereas KCl acidized with HCl appreciably improved it in one core. None of the used commercial additives significantly improved permeability. Injection of liquid CO 2 and isopropyl alcohol caused encouraging permeability improvement in some cores. Wax precipitation tests were carried out on both dead oil and live oil samples. It was found that precipitation occurred in the dead oil even at the reservoir temperature of 22°C. Filtration tests demonstrated that the live oil was much less sensitive to wax precipitation than the dead oil.

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Section: Verendrye Core #23mentioning

confidence: 99%

“…At this point liquid carbon dioxide was injected through the core since it is known to have some affinity to water (16) . Surprisingly, the permeability of the core rose to 4.3×10 -3 µm 2 , which is even slightly higher than the original brine permeability.…”

Section: Verendrye Core #23mentioning

confidence: 99%

Productivity Improvement in the Viking Reservoirs of West-Central Saskatchewan

Sayegh

Luo

Zhang

et al. 2009

Canadian International Petroleum Conference

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“…Water-based fracturing fluids are commonly used to fracture tight reservoirs in North America (Wasylishen and Fulton, 2012), and it has been reported that only 5% to 50% of the injected fluid is typically recovered as "flowback" (Zelenev and Ellena, 2009). Water loss to the formation can have detrimental effects on the hydrocarbon flow from chemical and mechanical damage, for example clay swelling or rock softening (Alramahi and Sundberg, 2012;Das et al, 2014;Zhang et al, 2015), to relative permeability damage due to capillary trapping of the water phase and water blocking (Abrams and Vinegar, 1985;Bennion et al, 2000;Dutta et al, 2014;Kamath and Laroche, 2003;Mahadevan and Sharma, 2005;Liang et al, Submitted).…”

Section: Introductionmentioning

confidence: 99%

“…Similarly, supplementing fracturing fluids with surfactants that reduce capillary trapping of water has been recognized as a potential solution to permeability damage due to water blocks (Bennion et al, 2000). Several studies have investigated the use of surfactant-based fluid additives to enhance flowback and regain matrix gas permeability (Penny and Pursley, 2007;Rostami and Nasr-El-Din, 2014;Zelenev and Ellena, 2009).…”

Section: Introductionmentioning

confidence: 99%

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

Liang

Longoria

et al. 2015

Day 2 Tue, September 29, 2015

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Fracturing fluid loss into the formation can potentially damage the hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field as a way to dissipate the trapped water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants can be potentially used to reduce the impact of fracturing fluid loss on hydrocarbon permeability in the matrix as well. Unconventional tight reservoirs can differ significant from one another, which could potentially make the use of these techniques effective in some cases while not in others. We present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically-fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants on hydrocarbon permeability for different initial reservoir conditions. From this work, we identify the mechanism responsible for the permeability damage in matrix and we then suggest criteria that can be used to optimize the fracturing fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.

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“…Another potential mechanism of damage is from capillary trapping of water near the fracture face. Water trapping in tight formations has been studied in the past (Bennion et al, 1996) and permeability damage due to water blocking has been documented (Abrams and Vinegar, 1985;Bennion et al, 2000;Tannich, 1975).…”

Section: Introductionmentioning

confidence: 99%

When Less Flowback Is More: A Mechanism of Permeability Damage and its Implications on the Application of EOR Techniques

Longoria¹,

Liang²,

Nguyen³

et al. 2015

Unconventional Resources Technology Conference

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Only a small fraction of fracturing fluid is recovered as flowback after hydraulic stimulation of low permeability formations. From the point of view of relative permeabilities, the minimization of fracturing fluid losses is desirable to maximize the flow of hydrocarbon. On the other hand, field observations indicate that wells where less fracturing fluid is recovered as flowback performed better in production, leading to an apparent contradiction. We present a physics-based model that can account for both of these observations. Our model is the result of an experimental investigation using a coreflooding sequence that simulates fracturing fluid invasion, fluid flowback and hydrocarbon recovery in a hydrocarbon-rich, hydraulically-fractured reservoir. We elucidate the interplay between capillary suction and viscous displacement of the fracturing fluid and the impact of water blocks on hydrocarbon permeability. This model reveals the inherent relationship between flowback and hydrocarbon production for different initial petrophysical properties and has implications on both well shut-in management and the use of chemical EOR techniques in tight reservoirs.

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Low Permeability Gas Reservoirs and Formation Damage -Tricks and Traps

Cited by 32 publications

References 11 publications

Productivity Improvement in the Viking Reservoirs of West-Central Saskatchewan

Productivity Improvement in the Viking Reservoirs of West-Central Saskatchewan

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

When Less Flowback Is More: A Mechanism of Permeability Damage and its Implications on the Application of EOR Techniques

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