Frac-Packing Openhole Completions: An Industry Milestone
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAlthough frac-packing has been widely and successfully used in cased-hole completions, open-hole frac-packing is not so common. It is well known that the efficiency of cased-hole frac-packs can be limited by the perforations. It can therefore be expected that open-hole frac-packing would provide higher productivity by eliminating a major choke in the flow path. In this paper, we present an open-hole frac-pack case history involving a highly-deviated, challeng… Show more
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Many engineers disregard laboratory reports demonstrating that the pressure losses across proppant samples are substantial. Similarly, it appears that the modeling studies warning of substantial productivity losses due to inadequate fracture conductivity have not been universally convincing. Perhaps many practical frac engineers simply object to the theoretical nature of these arguments, when they quote one of the more influential orators of our time, Shania Twain,1 stating, "That don't impress me much." Instead, many Petroleum Engineers prefer to see the economic benefit demonstrated in real reservoirs, and seemingly borrow a quotation from the film Jerry Maguire,2 stating, "Show me the money!" The purpose of this paper is to summarize the results of over 80 field studies where well productivity was improved by increasing the fracture conductivity. The benefit of increased conductivity has been demonstrated in oil, condensate, and gas reservoirs in 50 regions around the globe.This benefit was documented by 250 authors representing over 70 companies. Increased conductivity has been shown to be beneficial in oil wells producing 2 bopd to 25,000 bopd, and in gas wells producing less than 1 MMCFD to over 100 MMCFD. Higher conductivity fractures were proven to improve the cash flow in carbonates and sandstones at depths of 2800 to 20,000 feet, and in low rate coal bed methane wells shallower than 1500 feet. This review of industry experiences in a wide variety of reservoirs is not presented as a substitute for a comprehensive optimization study in a specific location. Instead, the following summary demonstrates that well productivity and profitability can frequently be improved with redesign of hydraulic fractures, despite the failure of many existing production models to predict those benefits. These studies are presented to satisfy the following goals:To verify that the extreme pressure losses observed in the laboratory and predicted by current fluid flow theory are real, i.e., "Proving It".To provide a list of fields, encompassing a wide variety of reservoir types, to assist engineers searching for results from an analogous field.To provide a number of field studies to which production models can be calibrated.To summarize the collective experience of over 250 authors, and incorporate what they have learned into future fracture designs.To demonstrate the relationship between fracture conductivity, well productivity, and cash flow, i.e., "Show me the money!" Introduction Over 100 years ago, Forchheimer3 recognized that fluid flow through porous media obeyed Darcy's Law only at extremely low seepage velocities. At typical velocities experienced in hydraulic fractures, the pressure losses actually consist of both a frictional and an inertial component. In other engineering disciplines, this concept is well accepted. Chemical Engineers routinely use this relationship (referred to by them as the Ergun Equation4,5) to describe fluid flow through catalyst beds and media filters. Automotive Engineers similarly understand that the pressure drop within a catalytic converter is not adequately described by Darcy's Law. In most industries, it is simple to measure the pressure loss across the system and use the correct equation. However, as Petroleum Engineers frequently pump proppant down a mile of pipe, and hundreds of feet away from the wellbore, our mistake may not be as readily apparent. Since we have yet to invent a remotely transmitting pressure gauge to place in the propped fracture, we instead choose to stick our heads in the sand and ignorantly assume Darcy's Law will adequately describe fluid flow in hydraulic fractures. We are simply wrong.
Many engineers disregard laboratory reports demonstrating that the pressure losses across proppant samples are substantial. Similarly, it appears that the modeling studies warning of substantial productivity losses due to inadequate fracture conductivity have not been universally convincing. Perhaps many practical frac engineers simply object to the theoretical nature of these arguments, when they quote one of the more influential orators of our time, Shania Twain,1 stating, "That don't impress me much." Instead, many Petroleum Engineers prefer to see the economic benefit demonstrated in real reservoirs, and seemingly borrow a quotation from the film Jerry Maguire,2 stating, "Show me the money!" The purpose of this paper is to summarize the results of over 80 field studies where well productivity was improved by increasing the fracture conductivity. The benefit of increased conductivity has been demonstrated in oil, condensate, and gas reservoirs in 50 regions around the globe.This benefit was documented by 250 authors representing over 70 companies. Increased conductivity has been shown to be beneficial in oil wells producing 2 bopd to 25,000 bopd, and in gas wells producing less than 1 MMCFD to over 100 MMCFD. Higher conductivity fractures were proven to improve the cash flow in carbonates and sandstones at depths of 2800 to 20,000 feet, and in low rate coal bed methane wells shallower than 1500 feet. This review of industry experiences in a wide variety of reservoirs is not presented as a substitute for a comprehensive optimization study in a specific location. Instead, the following summary demonstrates that well productivity and profitability can frequently be improved with redesign of hydraulic fractures, despite the failure of many existing production models to predict those benefits. These studies are presented to satisfy the following goals:To verify that the extreme pressure losses observed in the laboratory and predicted by current fluid flow theory are real, i.e., "Proving It".To provide a list of fields, encompassing a wide variety of reservoir types, to assist engineers searching for results from an analogous field.To provide a number of field studies to which production models can be calibrated.To summarize the collective experience of over 250 authors, and incorporate what they have learned into future fracture designs.To demonstrate the relationship between fracture conductivity, well productivity, and cash flow, i.e., "Show me the money!" Introduction Over 100 years ago, Forchheimer3 recognized that fluid flow through porous media obeyed Darcy's Law only at extremely low seepage velocities. At typical velocities experienced in hydraulic fractures, the pressure losses actually consist of both a frictional and an inertial component. In other engineering disciplines, this concept is well accepted. Chemical Engineers routinely use this relationship (referred to by them as the Ergun Equation4,5) to describe fluid flow through catalyst beds and media filters. Automotive Engineers similarly understand that the pressure drop within a catalytic converter is not adequately described by Darcy's Law. In most industries, it is simple to measure the pressure loss across the system and use the correct equation. However, as Petroleum Engineers frequently pump proppant down a mile of pipe, and hundreds of feet away from the wellbore, our mistake may not be as readily apparent. Since we have yet to invent a remotely transmitting pressure gauge to place in the propped fracture, we instead choose to stick our heads in the sand and ignorantly assume Darcy's Law will adequately describe fluid flow in hydraulic fractures. We are simply wrong.
Hydraulic fracturing combined with gravel packing in high-permeability gas reservoirs (frac-packing, or F&P) is currently considered the most reliable completion technology for offshore Gulf of Mexico (GoM) completions. Such treatments are designed to bypass damage near the wellbore and prevent formation sand production. Despite the relative maturity of this technology, there has been insufficient focus on non-Darcy flow, particularly in the fracture, in F&P wells in the literature. Previously published work, based on single-phase inflow equations, acknowledged that a very high pressure drop exists near the wellbore in F&P completions, but this has been usually attributed to a limited number of effective perforations. In this work, we used reservoir simulation and an inflow equation for pressure drop across the perforation tunnels to quantify the relative pressure drop contributions in the reservoir, fracture, and gravel pack system. We considered both non-Darcy and multiphase flow in our evaluation. We found that non-Darcy flow in the fracture and perforation tunnels results in substantial near-wellbore pressure drops for typical F&P gas wells with gas rates greater than 0.2 to 3 MMscf/D/ft. Increasing fracture conductivity and fracture lengths and using proppants with lower non-Darcy flow coefficients can help in reducing non-Darcy pressure drops and optimizing F&P completions. Introduction The frac-packing technique for sand control resulted in a significant productivity improvement compared with conventional gravel packing in the early 1990s.1 Frac-packing employs tip-screenout (TSO) hydraulic-fracture stimulation pumped with screens in place to reduce operational costs. By 2002, approximately 1,000 F&P treatments were being performed on a yearly basis. U.S. operators now apply this method to complete more than 60% of offshore wells.1 To pay back the large investments required to develop unconsolidated, high-permeability, deep-water reservoirs, it is necessary to produce wells at high rates. F&P wells are often completed subject to proppant size limits and produced subject to pressure drawdown limits to control sand production. At high rates, well productivity is often affected by non-Darcy flow, which increases the pressure drawdown at a given rate, or decreases the flow rate at a given pressure drawdown. Thus, optimizing F&P wells involves designing the completion and operating the well to achieve a balance between (1) production rates, and revenue, (2) completion costs, (3) non-Darcy flow effects, which reduces well productivity, and (3) prevention of sand production. To do this optimization requires knowledge of the pressure drops in all components of the completion-gravel pack, hydraulic fracture and reservoir-and the factors affecting these pressure drops. If we determine that we have excessive pressure drops in components of the system that we can affect, then we may be able to design better F&P treatments and improve the well productivity and profitability. The history, application, design aspects, and economic benefits of F&P treatments have been widely discussed in the literature.1–5 Despite the relative maturity of the F&P technology, there has been little focus in the literature on the effect of non-Darcy flow throughout the reservoir-fracture-pack flow system in F&P wells. Most of the focus has been on the effect of non-Darcy flow in the gravel-pack, with the implication that non-Darcy flow is not as significant in the fracture and reservoir. We summarize the literature pertinent to non-Darcy flow in F&P wells in the following sections.
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