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Interest is growing in drilling the Austin Chalk formation, with oil and gas companies hopeful that applying the latest unconventional resource development technologies can open a new chapter of expansion in a historically prolific play that dates to the 1920s.
Much of the new drilling is in areas of the Chalk that overlie some of the most active parts of the Eagle Ford Shale play in south Texas. Drillers there are taking advantage of the additional stacked play opportunities that can often be drilled with the same rigs and crews they are using in the Eagle Ford and sometimes in the same well. Some operators may have also drilled in the Chalk during the depths of the industry downturn to hold leases and temporarily defer deeper Eagle Ford wells.
The Austin Chalk extends from Mexico across south and east Texas and a large portion of Louisiana to Mississippi. The history of the Chalk play has seen several booms, the last one coming in the 1990s with the introduction of horizontal drilling. Cumulatively, the formation has produced 1.7 billion BOE with approximately 9,500 wells having been drilled there.
There is good reason to believe that abundant oil and gas resources remain in the Austin Chalk. The United States Geological Survey released a study of four Austin Chalk-area assessment units (AUs) in 2010 that estimated mean undiscovered resources for the Austin Pearsall-Giddings AU of 879 million bbl of oil, 1.3 Tcf of gas, and 106 million bbl of natural gas liquids (NGLs). Three other AUs were estimated to hold a combined mean 78 million bbl of oil, 2.3 Tcf of gas, and 257 million bbl of NGLs.
Among the most active participants in the latest Austin Chalk play have been EnerVest, EOG Resources, Encana, and Murphy. Other companies active in the Chalk include GulfTex Energy, ConocoPhillips, Devon Energy, Marathon, Abraxas Petroleum, and Chesapeake.
EnerVest, which acquires, develops, and operates oil and gas fields on behalf of its institutional investors, is the largest producer in the Austin Chalk. The company built a substantial position there beginning with its 2007 acquisition of Anadarko’s holdings in Texas’ Giddings field, which has been producing since the 1930s. EnerVest’s move into the Chalk came years before most other current players.
In the Giddings field, as in certain other parts of the Austin Chalk, the formation lies above the Eagle Ford. But Eagle Ford development has been minimal there, compared with core Eagle Ford activity taking place from 20 to 80 miles southwest of the field.
Interest is growing in drilling the Austin Chalk formation, with oil and gas companies hopeful that applying the latest unconventional resource development technologies can open a new chapter of expansion in a historically prolific play that dates to the 1920s. Much of the new drilling is in areas of the Chalk that overlie some of the most active parts of the Eagle Ford Shale play in south Texas. Drillers there are taking advantage of the additional stacked play opportunities that can often be drilled with the same rigs and crews they are using in the Eagle Ford and sometimes in the same well. Some operators may have also drilled in the Chalk during the depths of the industry downturn to hold leases and temporarily defer deeper Eagle Ford wells. The Austin Chalk extends from Mexico across south and east Texas and a large portion of Louisiana to Mississippi.
Baldwin, Amanda (Chesapeake Energy) | Lasecki, Leo (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy) | Porter, Lee (Chesapeake Energy) | Tatarin, Triffon (Chesapeake Energy) | Nicoud, Brian (Chesapeake Energy) | Taylor, Grant (Chesapeake Energy) | Zaghloul, Jose (Chesapeake Energy) | Basbug, Basar (NITEC) | Firincioglu, Tuba (NITEC) | Barati Ghahfarokhi, Reza (University of Kansas)
Implementation of miscible gas huff and puff (HnP) for Improved Oil Recovery (IOR) requires timely identification of prospective projects, a demonstration of economic feasibility through pilot testing, and efficient scale-up of HnP operations. HnP pilot design and execution of the pilot project requires a minimum of 9 to 12 months to procure, and another 8 to 12 months to construct and operate. A substantial capital investment, approximately $1 to $5 million per pilot well, is also required (Texas Railroad Commission & Industry Operators). The lead time for procuring specialized compression can require 9 to 15 months. These early purchases comprise a large proportion of project capital investment.
Collaboration by a variety of technical disciplines is required to efficiently design, construct, and operate a pilot with the goal of expanding IOR operations. An effective, collaborative approach allows for development of a HnP design that integrates both subsurface and surface design criteria.
A workflow for design of HnP pilot testing was developed to coordinate concurrent project efforts including completion of reservoir characterization, engineering, permitting, stakeholder review and approvals, gas contracting, construction, testing and full-scale execution. Effective coordination of these efforts will result in efficient project implementation with minimal impacts on project scope, schedule and cost. Use of the workflow also allows for timely identification and mitigation of multiple project risks associated with design, construction and operation of IOR.
Well executed pilot tests will accelerate the learning curve for application of HnP IOR in Eagle Ford wells; resulting in lower capital costs, lower operating costs, and increased operational reliability. Pilot test results will also be used to up-scale IOR operations in a cost-effective manner.
Abstract Characterizing vertical drainage in unconventional reservoirs developed using horizontal hydraulically-stimulated wells is a major challenge facing the E&P industry because there are few inexpensive, robust methods designed to measure vertical contributions. To overcome this challenge, ConocoPhillips has developed novel time-lapse geochemistry and production allocation techniques that utilize produced fluids (oil, gas, and water) to cost-effectively ascertain vertical drainage heights and provide information about vertical connectivity (or lack thereof) between stacked/staggered wells. In this paper, we present an overview of the geochemistry technique as well as geochemistry-based production allocation results in the Eagle Ford play. Over 3,000 time-lapse geochemistry samples have been collected over the last five years from over 150 Eagle Ford wells comprising more than 30 different pilot projects across ConocoPhillips more than 200,000-acre land position. The ‘fingerprints’ of the produced fluids have been quantitatively linked to specific stratigraphic layers using Eagle Ford core data. Key insights from this analysis are that vertical drainage is limited, varies across the acreage position, and is dynamic during production, usually shrinking with time. Results from time-lapse geochemistry have been integrated with multiple well pilot datasets (e.g., microseismic, soluble tracers, cores, image logs, pressure gauges in vertical and horizontal wells, and permanently-installed fiber optic cables) to optimize ConocoPhillips Eagle Ford development strategy. The outcome of these analyses has been the addition of approximately 1,200 drilling locations to the plan of development, which has significantly increased recoverable resources and asset value. Introduction Significant hydrocarbon resources are unlocked by horizontal drilling and hydraulic stimulation in low and ultra-low permeability (micro- and nano-darcy) reservoirs. Hydraulic fracturing creates a stimulated rock volume (SRV) around each producing lateral well from which hydrocarbons are accessed. The dimensions of the SRV are thought to be controlling factors in determining the optimal stacking and spacing of horizontal wells in a field development strategy.
The oil is there. The gas is nearby. The process is proven.
But is there an appetite to put it all together and redefine what it means to be a shale producer? This is the key question looming over the future of enhanced oil recovery for tight shale reservoirs, or simply shale EOR.
To answer it, unconventional oil producers are trying to weigh the options from what amounts to a complicated pros-and-cons list.
Developing a shale EOR program may mean drawing resources away from new exploration projects that have quicker returns, the same conundrum that has stymied the US refracturing market. On the other hand, shale EOR boasts impressive economics for companies willing to reinvest in land and wells already paid for.
This financial tug-of-war has been playing out in the shale sector since the spring of 2016. That was when Houston-based EOG Resources let it be known that its shale EOR program was boosting production from vintage horizontal wells in its Eagle Ford Shale asset in south Texas.
News of the development quickly made the operator synonymous with shale EOR. It is now widely understood that all of these projects rely on the huff-and-puff injection process using natural gas as the special agent that can unlock those additional barrels. Other key details are coming to light as well—such as the expanding scope of success.
In a recent quarterly earnings statement, EOG said it continues to see “strong results” from around 150 EOR wells, more than a third of which were converted in 2018. Analysts and engineering consultants have found about 100 other wells in the Eagle Ford that several other operators have converted into huff-and-puff injectors.
“It’s kind of incredible to see the data,” said John Watson, the senior research analyst who put together a report late last year that highlighted production details of shale EOR projects. After physically combing through filings at the Texas Railroad Commission (since they are not available to download), he found dozens of pad wells that saw a combined 10-fold rise in production above their trough.
Among the standouts, a group of 11 wells that reached a combined peak production rate in December 2011 of about 90,000 bbl a month. By August 2017, these wells were pumping out only 5,000 bbl. After gas injections began, the group produced 40,000 bbl a month—an average increase from about 15 B/D to 117 B/D per well.
Another case involved 14 wells that peaked at 330,000 bbl a month in 2013, then dropped to 10,000 bbl. Post injection, output increased to 170,000 bbl a month.
Watson’s report covers more than two dozen other shale EOR projects, though most lacked production results, revealing only project cost estimates. As opaque as the shale EOR effort has been thus far—at least outside of academic research—operators have shared these eye-openers for one simple reason: they have to. That is, if they want to receive the tax credits eligible for all EOR projects.