The First Application of a Novel Reservoir Simulation Approach Comprising Radial Drilling in the Niobrara Shale

Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.

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Production Rate Analysis of Fractured Horizontal Well considering Multitransport Mechanisms in Shale Gas Reservoir

Geofluids ◽

10.1155/2018/3148298 ◽

2018 ◽

Vol 2018 ◽

pp. 1-17 ◽

Cited By ~ 1

Author(s):

Qi-guo Liu ◽

Wei-hong Wang ◽

Hua Liu ◽

Guangdong Zhang ◽

Long-xin Li ◽

...

Keyword(s):

Production Rate ◽

Shale Gas ◽

Horizontal Well ◽

Production Performance ◽

Natural Fractures ◽

Gas Reservoir ◽

Isothermal Adsorption ◽

Well Production ◽

Shale Gas Reservoir ◽

Fractured Horizontal Well

Shale gas reservoir has been aggressively exploited around the world, which has complex pore structure with multiple transport mechanisms according to the reservoir characteristics. In this paper, a new comprehensive mathematical model is established to analyze the production performance of multiple fractured horizontal well (MFHW) in box-shaped shale gas reservoir considering multiscaled flow mechanisms (ad/desorption and Fick diffusion). In the model, the adsorbed gas is assumed not directly diffused into the natural macrofractures but into the macropores of matrix first and then flows into the natural fractures. The ad/desorption phenomenon of shale gas on the matrix particles is described by a combination of the Langmuir’s isothermal adsorption equation, continuity equation, gas state equation, and the motion equation in matrix system. On the basis of the Green’s function theory, the point source solution is derived under the assumption that gas flow from macropores into natural fractures follows transient interporosity and absorbed gas diffused into macropores from nanopores follows unsteady-state diffusion. The production rate expression of a MFHW producing at constant bottomhole pressure is obtained by using Duhamel’s principle. Moreover, the curves of well production rate and cumulative production vs. time are plotted by Stehfest numerical inversion algorithm and also the effects of influential factors on well production performance are analyzed. The results derived in this paper have significance to the guidance of shale gas reservoir development.

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A predictive protocol to obtain maximum water-free oil production rate for perforated vertical wells

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-01014-z ◽

2020 ◽

Author(s):

James O. Adeleye ◽

Olugbenga Olamigoke ◽

Oluseun T. Mumuni

Keyword(s):

Computational Model ◽

Production Rate ◽

Skin Effect ◽

Oil Production ◽

Cost Effective ◽

Water Production ◽

Skin Model ◽

Vertical Wells ◽

Flow Mechanisms ◽

Maximum Water

Abstract Producing an oilfield in a cost-effective way depends on how long water production could be delayed in the reservoir. Many flow mechanisms, correlations, and methods to calculate maximum water-free oil production rate have been published, However, those methods have generally failed to not consider the skin effect which affects the flow into the wellbore. In this paper, the semi-analytical perforation skin model as presented by Karakas and Tariq is incorporated into the Meyer and Garder correlation for critical oil rate from a perforated vertical well interval to obtain the maximum water-free oil production rate and optimal perforation parameters. The resulting coupled computational model is used to determine the sensitivity of the maximum water-free oil production rate to wellbore perforation parameters. Whilst an increase in perforation length and decrease in spacing between perforation increase the critical flow rate, an increase in perforation radius did not translate to higher productivity. The optimal perforation angles are 45° and 60°, however, for the data used in this work the maximum water-free oil rate of 23.2 std/d was obtained at 45° of phasing angle, 1 in of spacing between perforation, 0.36 in of perforation radius and 48 in of perforation length. Thus, the perforation strategy can be optimized prior to drilling and completion operations to improve productivity using the computational model presented in this work.

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Horizontal Well Completion with Multiple Artificial Bottom Holes Improves Production Performance in Bottom Water Reservoir

Mathematical Problems in Engineering ◽

10.1155/2020/7247480 ◽

2020 ◽

Vol 2020 ◽

pp. 1-11

Author(s):

Haidong Wang ◽

Yikun Liu

Keyword(s):

Pressure Distribution ◽

Horizontal Well ◽

Bottom Water ◽

New Technology ◽

Water Reservoir ◽

Pressure Profile ◽

Production Performance ◽

Well Completion ◽

Horizontal Wellbore ◽

Control Technologies

The horizontal well completion with stinger is usually used to control the bottom water cone. Although the pressure profile and the inflow profile along the horizontal wellbore can be divided into two parts by the stinger, these profiles have not really flattened. In order to flatten the pressure distribution and inflow distribution further, it proposes a new technology. This new horizontal well has multiple artificial bottom holes (MABH) along the wellbore and it has application potential. In order to verify the effectiveness of MABH technology, a model of horizontal well completion with MABH was established, and the production performance of different water cone control technologies was analyzed: conventional horizontal well, stinger completion horizontal well, and MABH completion horizontal well. The results show that the MABH technology has more advantages than the stinger technology. The uniformity of pressure distribution of the 6-MABH horizontal well is 55% higher than that of the horizontal well with string technology, and the uniformity of inflow distribution is increased by 65.25%. At the same time, although the operation of MABH technology is very simple, it should follow a rule of MABH installation: the position of the first MABH should be set at 242.5 m from the heel hole of the horizontal wellbore, and the other interval is 92.4 m.

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CoalBed Methane Pad Wells Completion and Artificial Lift Optimizations: Case Study From Australia Surat Basin DS Gas Field

10.2523/iptc-21451-ms ◽

2021 ◽

Author(s):

Li Ming ◽

Xia Zhaohui ◽

Liu Lingli ◽

Cui Zehong ◽

Duan LiJiang ◽

...

Keyword(s):

Coalbed Methane ◽

Optimization Methods ◽

Gas Production ◽

Production Performance ◽

Vertical Wells ◽

Coal Seams ◽

Gas Field ◽

Well Completion ◽

Artificial Lift ◽

Coalbed Methane Production

Abstract The Coalbed Methane in Australia Surat Basin is main gas source for LNG project in east coast of Australia[1]. Traditionally, Coalbed Methane are drilled by vertical wells. But there are big intensively farmed land coverage in the Surat Basin, the multiple wells on single, larger pad from the surface, the bores slant away at around 70 degrees to intersect multiple, thin coal seams are applied to avoid the extra "footprint" and decrease the environment affect. Many pad wells production failure because of poor interburden isolation. Excessive solids production in pad wells resulted in new failures of holes in tubing due to accelerated erosion, which bring big challenges for the Coalbed methane production in deviated pad wells. The gas production in pad wells are analysised and the new pad wells optimization are proposed. First, the complete wire log (at least include GR and density log curves) need to acquire for correct thin coal seams correlation and locate the interburden sandstone position for future good sandstone isolation. Second the customized completion strategy and placement (swell packer) are applied in the pad wells and specialized tubing with enhanced erosion resistance to extend the run life. Thirdly ESP pumps and optimized tubing are installed in new deviated wells for good gas production. After the pad wells were put into production, the gas production was kept well for long time without pump problems. Swell able packer completion significantly eliminates sand problem by isolating in excess of or close to 80% of interburden sand. The above well completion and artificial lift optimization methods bring good production performance for the new pad wells and contribute much production for the producing gas field. The swellable packer completion also can be used in vertical wells and will be standard well completion methods for future gas development wells.

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Hydraulic fracturing propagation mechanism during shale gas reservoir stimulation through horizontal well

Tehnicki vjesnik - Technical Gazette ◽

10.17559/tv-20151216024823 ◽

2016 ◽

Vol 23 (2) ◽

Keyword(s):

Hydraulic Fracturing ◽

Shale Gas ◽

Horizontal Well ◽

Propagation Mechanism ◽

Gas Reservoir ◽

Reservoir Stimulation ◽

Shale Gas Reservoir

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Production Performance Simulation of Horizontal Well with Hydraulic Fracturing

Unconventional Tight Reservoir Simulation: Theory, Technology and Practice ◽

10.1007/978-981-32-9848-4_9 ◽

2020 ◽

pp. 301-317

Author(s):

Qiquan Ran

Keyword(s):

Hydraulic Fracturing ◽

Horizontal Well ◽

Production Performance ◽

Performance Simulation

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Connecting the Dots: Multistage Fracturing in Horizontal Wells with Multilayered Reservoirs - Lessons Learned

10.2118/205302-ms ◽

2022 ◽

Author(s):

Ahmed Al Shueili ◽

Musallam Jaboob ◽

Hussain Al Salmi

Keyword(s):

Hydraulic Fracturing ◽

Learning Curve ◽

Horizontal Well ◽

Horizontal Wells ◽

Fracture Initiation ◽

Lessons Learned ◽

Production Performance ◽

Valuable Insight ◽

Tight Gas ◽

Fracture Height

Abstract Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.

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