Designing Hydraulic Fractures In Russian Oil And Gas Fields To Accommodate Non-Darcy And Multiphase Flow-Theory And Field Examples (Russian)

Dedurin, Andrey V.; Majar, Vadim A.; Voronkov, A. A.; Zagurenko, Alexey G.; Zakharov, A. Yu.; Palisch, Terry; Vincent, Michael C.

doi:10.2118/101821-ru

Cited by 17 publications

(6 citation statements)

References 12 publications

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“…A few other examples of production drop for wells producing below bubblepoint pressure were published by Dedurin et al (2006). But even with these uncertainties, the overall trend is clear.…”

Section: Spe-171147-msmentioning

confidence: 99%

Hydraulic Fracturing Optimization Restores Development Prospectives in the Challenging Environment of Rostashinskoe Oilfield, Orenburg Region

et al. 2014

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Orenburg region is a part of the Volga-Urals basin and, because of geological complexity, it poses problems for field development and reservoir stimulation. The Rostashinskoe field is one of the fields of the Pervomaysky group, and it has been under development since 1980. The main producing horizons of the field are Devonian: Afoninsky (DV), Vorobievsky (DIV), and Ardatovsky (DIII) formations. The Pervomaysky reservoir is unique in having very light oil.Oil traps in the Pervomaysky fields are formed by faulting. The entire area of these oilfields is now covered by 3D seismic surveys, which indicate that traps are related to a series of regional faults scattered from east to the west. Apart from the main regional faults, Pervomaisky fields have a large number of smaller low-amplitude faults, both conductive and sealed. The presence of these faults has significantly affected the field development strategy. The DIII formation of Rostashinskoe field is represented by two sandstone sublayers, DIII-1 and DIII-2. Large numbers of faults and pinchout zones have imparted a high degree of formation heterogeneity both vertically and laterally across the field. As a consequence of heterogeneity, Rostashinskoe presents difficulties with proper waterflood and fracturing modelling in the field development cycle. As a result, reserves are being recovered unequally across the field.The first trials of hydraulic fracturing in 2004 were unsuccessful because of high fracturing-treatment pressure, a large number of screenouts, and difficulties with fracture fluid flowback and well kickoff. To investigate flowback problems and fast production decline, detailed core analysis has been performed, including mineralogical composition and core flow testing with fracturing fluid to determine the fluid's influence on core permeability. It was determined that Rostashinskoe cores have clay migration problems and changes in wettability. Based on core analysis data, a new clay stabilizer and surfactant were recommended for fracturing fluid. Optimization of the fracturing fluid has led to significant improvement in final productivity results after fracturing and basically has proven the efficiency of hydraulic fracturing treatments in the Rostashinskoe field. From 2010 to 2013, over 60 fracturing jobs were performed in the Rostashinskoe oilfield. Proper candidate selection, optimized fracturing design, and best practice led to additional oil recovery from the DIII formation.Success of the modified fracturing design has rejuvenated the infill drilling program in the Rostashinskoe oilfield to achieve increased production, reduced decline rate, and better reserves recovery.

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Section: Spe-171147-msmentioning

confidence: 99%

Hydraulic Fracturing Optimization Restores Development Prospectives in the Challenging Environment of Rostashinskoe Oilfield, Orenburg Region

et al. 2014

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“…Maintaining a higher BHP also limits closure of micro-fractures, critical to oil production and overall reservoir permeability [Dedurin et al, 2006]. Proper flowback procedures, rigging, and equipment were critical to preventing and/or limiting lost time after screen-outs, or after pressure-outs during wireline pumpdowns.…”

Section: (10) Control Flowback and Restricted Flowratesmentioning

confidence: 99%

Optimized Production in the Bakken Shale: South Antelope Case Study

West

Harkrider

Barham³

et al. 2013

All Days

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Focused modifications in drilling, reservoir, and completion engineering from 2009 to the present have improved Bakken, specifically the South Antelope Field, production as much as 50% to 75%. To achieve these results, Helis Oil and Gas Co., LLC formed a multi-disciplinary team in 2008 which it tasked with evaluating and overhauling its completion approach. Pre-2008 completions followed conventional wisdom: target the Middle Bakken Formation between the Lodge Pole and the Three Forks Formations. Pre-2009 wellbore constructions included "kick outs" (i.e., multi-lateral), open-hole completions; short laterals; single-stage ported subs; sliding sleeves; and long stage intervals and were erratic and inconsistent. The designs and procedures resulted in a high percentage of pre-mature screenouts. In addition, the production responses on these Middle Bakken completions averaged 330 bopd with an estimated ultimate recovery (EUR) of 300 MBOe. During the pre-2009 period, 3 Three Forks were completed and these wells produced on average 550 bopd. After evaluating the pre-2009 results, the team recommended 10 changes: (1) change landing target to the Three Forks; (2) increase lateral lengths ~2x from "640's" to "1280's"); (3) increase formation contact (completion method, stage lateral length and, perforation spacing/density); (4) refine pump-down operations; (5) implement critical fracturing mechanisms diagnosis; (6) incorporate proppant selection (ceramic versus sand); (7) refine flush procedure to include monitoring and assure consistency; (8) integrate on-site, real-time pressure management and proppant schedule including proppant slugs, altered mesh types, and adjusted ramp schedule; (9) adjust treatment fluid design (25-lb gel loading instead of 40-lb gel loading); and (10) implement flowback and flowrate control. Implementing these recommendations, Helis deviated from conventional Williston Basin philosophy and drilled 30 "1280's" in 2010-2012. These wells resulted in ~1,500 bopd with a maximum of 2,500 bopd and EUR's of ~1,200 MBOe. They are among the best wells in the Williston Basin. In comparison, direct offset well EUR's averaged less than 750 MBOe. The success of these wells is not the result of one breakthrough but rather the result of sound changes to engineering techniques that were carried out systematically. Applying these engineering practices, maintaining strict adherence to recommended practices, and not making drastic, unfounded changes ultimately optimized production in this Bakken project.

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“…Even when assuming simple, planar fractures and optimistic frac widths, it is evident that hydrocarbons must travel at superficial velocities 1,000,000 times greater in the transverse fracture than in the formation [Dedurin 2006] and it is challenging to place sufficient conductivity in the near wellbore area [Shah 2010, Rankin 2010, Dedurin 2006]. For this reason, operators should always be concerned with improving the width, conductivity, and durability of the fracture near the wellbore in transverse fractures.…”

Section: Flow Convergencementioning

confidence: 99%

Optimizing Transverse Fractures in Liquid-Rich Formations

Vincent

2011

SPE Annual Technical Conference and Exhibition

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Horizontal wells provide the opportunity to initiate multiple transverse fractures and dramatically increase the connection between the wellbore and the hydrocarbon-bearing reservoir. This has allowed the economic development of low permeability reservoirs that cannot be pursued without reservoir stimulation. Our success, however, does not imply that we are optimized. Recent field results in the Niobrara, Bakken, Viking, Haynesville, Eagle Ford and other reservoirs completed with transverse fractures are yielding answers to many questions, including: Are we achieving acceptable vertical height growth? What adjustments are necessary to accommodate multiphase flow? What fracture conductivity is needed? How many frac stages will provide the optimal economic returns? Are we effectively stimulating each stage? Are precautions necessary to avoid or reduce overflushing of proppant? Will restimulation of these reservoirs be necessary given current completion strategies? This paper explains the challenges of accommodating multiphase flow in transverse fractures and summarizes theoretical, laboratory, and field results demonstrating the best practices. Evidence is reviewed indicating that fractures fail to sustain hydraulic continuity through many laminations and techniques are suggested that can improve the ability to drain multiple stacked pay intervals with horizontal wells. Updated production results from the Bakken and Eagle Ford should be of benefit to any operator stimulating horizontal wells that produce significant oil, water, or condensate volumes.

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Designing Hydraulic Fractures In Russian Oil And Gas Fields To Accommodate Non-Darcy And Multiphase Flow-Theory And Field Examples (Russian)

Abstract: TX 75083-3836 U.S.A., fax 01-972-952-9435.

Cited by 17 publications

References 12 publications

Hydraulic Fracturing Optimization Restores Development Prospectives in the Challenging Environment of Rostashinskoe Oilfield, Orenburg Region

Hydraulic Fracturing Optimization Restores Development Prospectives in the Challenging Environment of Rostashinskoe Oilfield, Orenburg Region

Optimized Production in the Bakken Shale: South Antelope Case Study

Optimizing Transverse Fractures in Liquid-Rich Formations

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