When methane is found in water wells near an unconventional well, fingers point to facturing as the liklely suspect. But a study of wells in the Utica Shale named other sources. In unconventional plays, comparing the effect of different completion designs or well-management strategies on well performance remains a challenge because of the relatively brief production history and lack of long-term field analogs of these plays.
The Italian operator reported positive appraisal and exploration results from wells drilled some 10,000 km apart. UK operator Trident Energy is entering Brazil while Australian firm Karoon Energy is expanding its position in the country. Both will try to boost output from already-producing assets. Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. Mexican President Andrés Manuel López Obrador is prioritizing investment in Pemex over foreign participation as a means to boost the country’s shrinking oil output.
The shale sector is studying the results of a 23-well experiment in the southeastern corner of New Mexico to learn what the wider implications might be. Researchers from the Federal Reserve Bank of Dallas quantified the economic impact of the US shale revolution for the first half of this decade. The green light for Santos Energy’s drilling program in the McArthur Basin comes after a moratorium on hydraulic fracturing in the Northern Territory was lifted in 2018. Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. Permian Basin operators and service companies met to discuss completions diagnostics, flowback strategies, water management, and artificial lift strategies.
Learning by doing is taking on a new meaning at universities that are constructing "science wells" to study shale exploration and production from below, and above, the surface. West Virginia University has begun drilling two gas wells with a vertical observation well in between them on a site not far from its campus in Morgantown, West Virginia. The heavily instrumented vertical well is at the heart of the work by the Marcellus Shale Energy and Environmental Laboratory, a public/private partnership created to take an unusually detailed and public look at a gas well in the prolific formation. "We thought of it as a tool for teaching, as a research lab, as well as a permanent part of the vision of what we want to do," said Brian Anderson, director of West Virginia University's Energy Institute, which coordinates projects including the Marcellus Shale laboratory. The university has partnered with Ohio State University, which is working on a companion effort called the Utica Shale Energy and Environment Laboratory.
The Deep Dry Utica, also known as the Extensional Utica, is a newly recognized shale play in Pennsylvania and West Virginia. The most developed part of the dry gas Utica shale, in Monroe County, OH, is an inexact analogue as it shares limited characteristics with the Deep Dry Utica to its east. Unconventional workflows based on analogue plays often rely on the statistical significance of trends, impossible to exploit when each data point in a new play is unique, and results are unrepeatable. With only the data from a handful wells in the public domain, and a few wells being drilled by operators where the data is still private, understanding the reservoir and geologic complexity of the Deep Dry Utica has eluded most operators. The play has seen early successes and failures, with wells exceeding initial production rates (IP) of 60 MMcf/day and wells so difficult to drill that they were unable to be completed due to financial limitations. Thus, structurally complex shale plays like the Deep Dry Utica with limited data require a new methodology to rapidly move from delineation to development mode. With a limited heterogeneous data set, subsurface modeling and data analytics in conjunction with analogue analysis allow operators to rapidly understand performance indicators, optimize location selection, well spacing, horizontal drilling and completion designs.
This paper describes the modeling and analytics-based workflow utilized to unlock commercial viability of the Deep Dry Utica, making the play commercially competitive with Marcellus Shale development. The workflow described in this paper utilizes earth modeling, reservoir and completion modeling and contemporary data analytics techniques to accelerate development. The workflow is demonstrated in a case study from the Deep Dry Utica in Pennsylvania, moving from delineation to commercial development, with less than a dozen data points across 500,000 thousand acres.
Oil and gas consulting and business intelligence data firm Rystad Energy sees “a very promising year” for shale oil producers, analysts at the firm’s North America shale webinar said recently. Based on the most recent data, he said, “We think the 10-million-barrels-a-day mark has already been reached and it happened in late 2017.” Abramov said that the US shale industry in 2018 faced “very limited bottlenecks on the well economics side and [with] efficiency” but noted that service industry bottlenecks “where the situation in many segments remains very tight” could impose some constraints. He said United States shale producers face a base decline rate of 3.1 million B/D from existing wells over the next 3 years but that the industry will likely be able at least to offset that decline. Only minimal growth beyond that will be required to offset the decline rate, and “a majority of operators are considering expanding their rig counts this year,” he said.
In the Eagle Ford, denser development means that in the future the number of child wells is likely to exceed the number of higher-producing parent wells. Maintaining production in the shale business is getting increasingly costly because new wells in major US shale plays are falling short of output from the parent wells. A study of 10 major US basins by Schlumberger (SPE 189875) found that while the parent and child wells looked comparable at first glance—about half of new wells outperform the older wells and vice a versa—the picture changes when the results are adjusted for the higher cost of drilling and fracturing new wells. This is a pressing issue in the shale sector where constant drilling is required to replace short-lived older wells, which is leading to increasingly dense development. Maintaining production in the shale business is getting increasingly costly because new wells in major US shale plays are falling short of output from the parent wells.
The Delaware Basin is one of the most active drilling areas in the U.S. This review of activity, well performance, and drilling economics was done using 7 years (2010-2016) of production and completion information. Normalized production type curves were developed for the primary Delaware Basin horizontal targets, the Bone Spring Sand and Wolfcamp Shale. Production and completion information from over 6,000 wells were considered along with several published operator presentations. Select high performing wells were identified and individually forecasted to identify the top 10 wells for 2016.
Our analysis shows that 1,007 Bone Spring and Wolfcamp wells were spudded and 894 new wells were put on production in 2016. Anadarko Petroleum, Concho Resources and EOG Resources were the most active operators in the Delaware Basin. From 2015 to 2016 drilling activity declined in the Bone Spring Sand by 57% while Wolfcamp Shale activity increased by 9%. Most U.S. shale plays experienced drilling declines of 30% or more in 2016, which highlights the resilience of the Wolfcamp Shale. See U.S. drilling play data below.
New well production rates and reserves have been increasing for the last 6 years. A typical new well drilled in the Bone Spring Sand should produce about 795,000 barrels of oil equivalent (BOE) over its life and new Wolfcamp Shale wells should produce 1,116,000 BOE. At current product prices ($50 Oil and $3.10 Gas) and well costs, new wells should payout in less than 2 years and generate an internal rate of return (IRR) of ~38% from the Bone Spring Sand and ~52% from the Wolfcamp Shale. Based on initial production rate and reserves per well, Resolute Natural Resources’ wells in the Wolfcamp Shale were the top performers in 2016.
Unconventional plays have proven to be highly challenging businesses. Aside from low commodity prices, the capital intensive requirement makes the development of unconventional reservoirs such as the Marcellus, a balancing act between costs and reservoir performance. Completion operations account for more than half of the capital requirement to execute unconventional wells and are one of the few elements operators can adjust and optimize. Gas rates, production declines and ultimate recoveries have been linked to completion parameters; hence, the economics of an unconventional play are influenced by completions design.
A number of completions design changes have been tested in the Marcellus basin. Two tests that have shown promising results were increasing the pounds of sand per lateral foot (commonly referred to as sand loading) and reducing the distance between perforation clusters, often referred to as reduced stage spacing (RSS) or reduced cluster spacing (RCS). A trend in these changes across the basin points to increased sand loading and reduced stage length can improve wellbore performance. With the combination of rate transient analysis (RTA) analysis and frac modeling these design changes correlate with increased stimulated reservoir volume (SRV) which is the source of the increased wellbore performance. Changes to the SRV need to be taken into consideration when optimizing lateral spacing. The process that is presented in this paper is aimed at merging the observed results with field planning to optimize wellbore performance and field economics.
This study highlights the complexity of unconventional reservoirs and reinforces the need for multidisciplinary approach to optimize the development of the unconventional. The results show relations between reservoir indicators and completions parameters based on results of more than four hundred wells. Rate transient analysis (RTA) was used to assess completions effectiveness by correlating execution with normalized A√k . The production analysis results were used as a correlation see6d to completion parameters performed in the development life of the Marcellus field. A completion effectiveness model was developed based on the results and used to forecast well performance. Finally, findings were tested with two case studies in the Marcellus shale.
The Bobcat No. 1 well in Gonzales County, Texas, lies in the Eagle Ford Shale but outside of the core development area. A scientific approach heavy on data and analysis has driven the successful effort of Battlecat Oil & Gas to develop unproven Eagle Ford acreage outside the core of that prolific Texas shale play. Andrew Fisher, a company engineer, gave a detailed presentation recently to the SPE Gulf Coast Section’s Houston Northside Study Group on the technical and economic data behind Battlecat’s highly productive Bobcat No. 1 oil well in Gonzales County. The Bobcat well came on stream in the second half of 2015 at an initial production rate of 375 B/D with an estimated ultimate recovery (EUR) level of 317,000 bbl. Completed horizontally with a hydraulically fractured 4,400-ft lateral section, Bobcat No. 1 ranked as the top EUR well in Gonzales County, per normalized lateral foot, at true vertical depths of 8,000 to 9,000 ft.