Cost/Benefits of Horizontal Wells

Joshi, S.D.

doi:10.2118/83621-ms

Cited by 64 publications

(21 citation statements)

References 18 publications

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“…Besides the down fall of oil production rate and wastes of reservoir energy, operating cost of in the surface production operations also increases due to handling, treatment, and disposal of large quantities of produced water (Sharma et al 2009;Al Hasani et al 2008). Horizontal wells have been used to produce thin zones, fractured reservoirs, formations with water and gas coning problems, waterflooding, heavy oil reservoirs, gas reservoirs, and in EOR methods such as thermal and CO 2 flooding (Joshi 2003).…”

Section: Introductionmentioning

confidence: 99%

Sensitivity study of horizontal length, offset from water oil contact and withdrawal rate of horizontal well in bottom water drive reservoir

Kumar

Sharma

Gupta

2017

J Petrol Explor Prod Technol

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Estimation of critical rate is required for maximizing oil production from horizontal well before water breakthrough. Post-breakthrough recovery is dependent on parameters viz: Horizontal length (L), withdrawal rate (Q) and offset from WOC (h). Critical rate has been determined using various analytical methods whereas EUR from horizontal well has been calculated for forty-eight cases (L-4 no's, Q-3 no's, h-4 no's) using commercial black oil simulator. Result of the study shows that maximum impact on cumulative oil production is given by offset from WOC followed by withdrawal rate and lastly on horizontal well length.

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Section: Introductionmentioning

confidence: 99%

Sensitivity study of horizontal length, offset from water oil contact and withdrawal rate of horizontal well in bottom water drive reservoir

Kumar

Sharma

Gupta

2017

J Petrol Explor Prod Technol

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“…Horizontal wells have been widely used to increase wellbore contact with the reservoir, increase flowing area, and thus, increase the well productivity by reducing coning tendencies, mitigating the risk of sand production, connecting disconnected drainage areas, and generally lowering drawdown-related production problems (Babu and Odeh 1989;Joshi 2003;Dikken 1990;Ihara et al 2013;Novy 1995).…”

Section: Introductionmentioning

confidence: 99%

Design of flow control devices in steam-assisted gravity drainage (SAGD) completion

Banerjee

Hasçakir

2017

J Petrol Explor Prod Technol

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Commercialization of the steam-assisted gravity drainage (SAGD) process has made recovery of heavy oil/bitumen possible in a number of reservoirs hindered by hydrocarbon immobility. However, the economics of this process are highly sensitive to the efficiency of steam creation, delivery, and use, with a successful and unsuccessful SAGD well pair often separated by how effectively thermal inefficiencies can be mitigated in the flow profiles of steam injection and/or in emulsion recovery. To improve flow profiles, Albertan SAGD completions have experimented with the addition of flow control devices (FCDs). These completion tools have historically been used to regulate liquid inflow across long producing laterals, adding a variable pressure drop along the lateral to improve the conformance of hydrocarbon production and delay water breakthrough; within SAGD completions, FCDs find novel use to force a more even flow distribution of steam in the injector and a thermally dependent inflow profile in the producer to maximize recovery of heavy oil/bitumen. This paper provides a comprehensive overview of different FCD designs, discussing their respective methods of regulation, the fluid-adaptive behavior of ''autonomous'' FCDs, operational strengths and weaknesses of different commercial offerings, and suggestions on how to use existing pressure loss models for FCDs and apply them to the non-traditional application of regulating SAGD flow profiles, both for equipment sizing and estimation of pressure loss/flow rates across the device. From this work, it is proposed that use of autonomous FCDs in the production lateral are of greater value than use of flow control in the injector; however maximum benefits are achieved by coupling simple orifice-style FCDs in the injector lateral with autonomous, large flow path (nonorifice) FCDs capable of controlling steam flash events in the production well.

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“…This, for example, helps in more production as it provides larger exposure to the formation, so the hydrocarbon can more easily being produced. Drilling nonvertical wells is more important in unconventional reservoirs such as gas shales or tight formations as the hydrocarbon bearing formations in such reservoirs exhibit very low permeability and having large exposure to the wellbore wall is essential for economical production rate (Joshi [2])…”

Section: Introductionmentioning

confidence: 99%

Determination of safe mud weight windows for drilling deviated wellbores: a case study in the North Perth Basin

Rasouli

2012

Petroleum and Mineral Resources

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Drilling non-vertical wells, which is commonly used to enhance production, in particular in unconventional reservoirs with very low permeability, is subjected to rock mechanics related issues namely wellbore instabilities. Drilling in the same formation but with different deviations and at different directions would not result in similar response in terms of rock failures. This is due to the rotation of the induced stresses around the wellbore wall along its trajectory. The type of instabilities that the formation experiences around the wellbore is a function of formation's mechanical properties and the status of in-situ stresses. It is clear that none of these natural parameters can be controlled or changed during drilling operation. However, the density of the mud weigh which is used to drill the wellbore could be optimised in order to mitigate or stop wellbore instability issues in the form of tensile failure or fracturing in case of using high mud density or shear failure or breakouts when a low mud weigh is used. Therefore, a safe mud weight window (MWW) can be determined for optimum drilling in terms of having the least issues related to wellbore instabilities. This MWW will change as the wellbore deviation changes.In this paper, the concept of constructing the rock mechanical model (RMM) which includes the rock mechanical properties as well as in-situ stress profiles is briefly presented. Then the RMM output corresponding to vertical well Arrowsmith-1 which is a shale gas well drilled in the North Perth Basin of Australia will be used to calculate the safe MWW for drilling wellbores in different azimuth and deviation in the field. The results indicate how the MWW changes as a function of wellbore trajectory.

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Cost/Benefits of Horizontal Wells

Cited by 64 publications

References 18 publications

Sensitivity study of horizontal length, offset from water oil contact and withdrawal rate of horizontal well in bottom water drive reservoir

Sensitivity study of horizontal length, offset from water oil contact and withdrawal rate of horizontal well in bottom water drive reservoir

Design of flow control devices in steam-assisted gravity drainage (SAGD) completion

Determination of safe mud weight windows for drilling deviated wellbores: a case study in the North Perth Basin

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