Development of Unconventional Gas Resources: Stimulation Perspective

Zahid, Salman; Bhatti, Amanat Ali; Khan, Hasnain Ahmad; Ahmad, Toseef

doi:10.2118/107053-ms

Cited by 31 publications

(4 citation statements)

References 15 publications

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“…To meet this demand, the hydrocarbon industry has raised its investment in exploration and production operations. However, with the depletion of the world's conventional resources, the interest in the exploitation of unconventional plays has increased over the past decades (Leimkuhler and Leveille 2012;Wang et al 2015;Zahid et al 2007). In the 1970s, such assets were not considered as economically viable resources for development mainly due to their low permeability (Eftekhari 2016).…”

Section: Introductionmentioning

confidence: 99%

Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

Dheyauldeen

Al-Fatlawi

Hossain

2021

J Petrol Explor Prod Technol

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The main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

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Section: Introductionmentioning

confidence: 99%

Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

Dheyauldeen

Al-Fatlawi

Hossain

2021

J Petrol Explor Prod Technol

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“…Tight oil and gas reservoirs, considered "unconventional resources", have been emerged as a significant source of energy supply in the United State and Canada, to supplement the decreasing supply of conventional resources and meet the increased global demands on oil and gas (Frantz et al, 2005;Zahid et al, 2007;Khlaifat et al, 2011). Unconventional resources with ultralow matrix permeability are capable of producing oil and gas at economic rates when completed by hydraulically fractured horizontal wells (Ning et al, 1993).…”

Section: Introductionmentioning

confidence: 99%

Advances in Understanding Liquid Flow in Gas Shales

Ghanbari

Dehghanpour

et al. 2014

Day 1 Tue, September 30, 2014

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Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, and clay swelling on imbibition behavior.We systematically measure the imbibition rates of fresh water, brine and oil into the confined and unconfined rock samples and crushed packs from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that confining the shale samples decreases the water imbibition rate of samples tested parallel to the bedding. However, it has a negligible effect on water uptake of samples tested perpendicular to the bedding and on ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. The liquid imbibition and ion diffusion rates along the bedding are higher than those against the bedding. Surprisingly, the crushed samples show a completely different behavior. The oil uptake of crushed packs is higher than their water uptake. The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by complete spreading of oil on fresh break surfaces of the rock.

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“…Unconventional resources (very-low permeability gas/oil reservoirs) have emerged as a significant hydrocarbon source (Clarkson and Pederson, 2010) to supplement the decreasing supply of conventional resources and meet the world's growing energy demand (Zahid et al, 2007;Abdelaziz et al, 2011). Economic production of unconventional resources has been made possible by the combination of horizontal drilling and hydraulic-fracturing techniques.…”

Section: Introductionmentioning

confidence: 99%

Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model

Ezulike

Dehghanpour

Hawkes³

2013

All Days

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Existing rate transient models for fractured horizontal wells assume single-phase fluid flow. This assumption is violated in early times, when hydraulic fractures (HF) are filled with fracturing water and hydrocarbon. This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate and pressure data measured during flowback operations. Existing models for analysing multiphase data from solution-gas drive and high-water-saturation conventional reservoirs cannot be applied to flowback data because of simplifying assumptions such as (1) constant average phase saturation with time, (2) constant rate or pressure well constraint and (3) radial flow. This paper extends the existing linear dual-porosity model (DPM) and develops a flowback analysis model (FAM) which accounts for transient multiphase flow in HF.The proposed model adopts an explicit dynamic-relative-permeability (DRP) function of time for hydrocarbon phase in the fracture network to account for water-saturation drop. This model assumes that water-saturation drop with time causes a corresponding non-linear increase in hydrocarbon relative-permeability in HF. The DRP function is obtained from analysing cumulative hydrocarbon + water measured during flowback operation and drainage relative-permeability curves from existing literature. Fifteen tight oil, tight gas and shale gas wells completed in the Bluesky, Cardium, Evie, Muskwa and Otter-Park Formations were used for this study. The resulting DRP parameters control the rate of water-saturation drop in HF (clean-up rate). DRP is incorporated into the existing DPM to obtain FAM flow equations. This paper attempt solving these equations with Mellin transforms under variable bottom-hole rate and pressure well constraints.FAM converges to the existing DPM at the limit of residual water-saturation. DRP captures the fluid physics from flowback phase till the "full" hydrocarbon production phase in the life of a multifractured horizontal well. The application of FAM on transient 2-phase flowback data (rate + pressure) could help estimate key reservoir parameters (e.g. effective HF half-length) and evaluate flowback performance (e.g. percentage of total inject fluid left in HF and matrix and the speed of HF clean-up). Results from this study is applicable for interpreting 2-phase flowback data from multi-fractured horizontal wells completed in tight and shale reservoirs. This study allows the industry to forecast hydrocarbon recovery from flowback data and estimate/predict the effectiveness of flowback operations. SPE 167164Careful management of flowback procedure is crucial to (1) obtain accurate physical and chemical data measurements and (2) prevent damage to the stimulated well (Crafton, 2008(Crafton, , 2010 and (3) improve well clean-p and maximize load recovery (Crafton, 1998). Accurate data ensures representative flowback volumetric, rate + pressure transient, and chemical analyses. These analyses provide (1) important well and reservoir informat...

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Development of Unconventional Gas Resources: Stimulation Perspective

Abstract: fax 01-972 952-9435.

Cited by 31 publications

References 15 publications

Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

Advances in Understanding Liquid Flow in Gas Shales

Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model

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