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Abstract The Delaware Basin encompasses 6.4 million acres throughout Southeastern New Mexico and West Texas. With large players such as ExxonMobil, Shell or Oxy typically grabbing headlines, it's easy to forget the multitude of smaller public and private E&P operators who exist in and around the acreage positions of the aforementioned companies. Regardless of the size of the acreage holding, a consistent theme is that a typical horizontal well drilled and completed (D&C) will yield water cuts of 60-90% at any given period in its productive lifespan. Saltwater production, handling and disposal (SWD) is a drag on lease operating expenses (LOE). SWD costs via trucking, pipeline, or on-lease SWD wells can range between $0.50-$3.00/bbl. As existing infrastructure is exhausted, water handling costs have been projected to rise to over $5.00/bbl. Additionally, restricted access to SWD could cause production curtailments and thus impacting operators beyond direct LOE. Well completion operations are impacted by freshwater procurement costs starting around $0.75/bbl. Regardless of final frac design, water consumption during fracturing operations typically exceeds 500,000 bbls or $375,000 per well. Significant value exists for recycling produced water via an on-lease pit and utilizing it for future frac operations. The produced water turns into an asset if the operator can efficiently manage to substitute higher and higher percentages of freshwater with produced water. Many smaller operators (defined as less than 50,000 acres) may view produced water recycling as an operation best left to large E&P's with their massive capital budgets and contiguous acreage. Fortunately, even a 5 well, section development plan can yield returns from an on-lease produced water recycling program.
Authors JW Blaney, Andreas Michael, Michael Cronin, and Abhijeet Anand are members of the TWA Editorial Committee. Prospectus: At a macro-level, midstream congestion due to insufficient pipeline takeaway is limiting production and development potential in the Permian Basin. However, maintaining profitability and a social license to operate requires sensible management of oil, gas, and water. It is easy to forget that our industry produces many times more water--that must be treated, recycled, and/or disposed of--than hydrocarbon. Water oil ratios (WOR) between 2:1 and 15:1 are not uncommon, which has increased competition for space in saltwater disposal (SWD) injection wells.
The sourcing, handling, and disposal of water is an increasing issue in US tight oil and gas operations and represents both a threat to operators and an opportunity for the supply chain. Both well count and completion intensity have grown in recent years and rising pressure from environmental regulations--e.g., federal Clean Water Act, Colorado's Senate Bill 181, etc.--means that water management has become a key focus for operators, specifically produced water disposal and recycling. Following the downturn, the recovery in activity levels translated to not only an increase in the number of wells completed, but more importantly longer laterals using more proppant (frac sand) and water per foot during hydraulic fracturing, which created more flowback and produced water. In the Delaware Basin, the water cut for wells has increased from an average of approximately 70–72% since 2016. Based on data from Westwood's Energent service, a Centennial Resources 2-mile lateral in the basin uses about 26 million pounds of 100-mesh frac sand and approximately 22 million gallons of water to achieve a 47-stage fracture.
Frac water demand in the Permian Basin is high and shows no signs of slowing down. According to Rystad Energy, operators by the end of this year will be using more frac water in the Permian than what was used in every US basin combined in 2016. The Delaware Basin accounts for 17% of the frac water market, and of that Rystad identified 60% of the market share coming from the top 10 operators in the Permian (Pioneer, Concho, EOG, Apache, Oxy, Exxon Mobil Corp., Anadarko, Diamondback Energy, Chevron, and Devon). More than 2 billion bbl of produced water comes from the Permian, and flowback water has increased 300% since 2016, but Rystad's vice president of shale research said the water treatment market has not grown at a similar rate. Speaking at an information session to discuss developments in oil and gas, Benjamin Stewart addressed the factors behind the growth of the water disposal market in the Permian as well as the state of the wider treatment market.
The inaugural SPE Permian Basin Production Management Symposium was a 1-day gathering held at the Midland Petroleum Club in April. The purpose of the event was to share operators' updates on completions diagnostics, flowback strategies, water management, and artificial lift strategies. Nine Permian Basin operators and three technology companies presented at the symposium, covering case studies in the Midland and Delaware basins. Takeaways discussed below only cover content from presentations that were agreed to be released to the public. George King of Viking Engineering kicked off the symposium by discussing the necessary geomechanical, geological, and well construction data needed for optimal completion designs.
Schlecht, Mathias (Biota Technology) | Sawadogo, Jordan (Biota Technology) | Sadeghi, Simin (Biota Technology) | Reeve, Nico (Biota Technology) | Haggerty, Matthew (Biota Technology) | Liu, Joanne (Biota Technology) | Ursell, Luke (Biota Technology)
Permian operators have dramatically increased the number of multi-stage fractured horizontal wells over the past 5 years and face challenges associated with maximizing production of existing wells while developing new acreage and benches, all the while meeting capital return requirements. Over that time, DNA diagnostics have been applied successfully to more than 1000 wells throughout the Permian Basin to help operators reduce uncertainties ranging from drained rock volume, well-well communication, and sources of water production.
When subsurface conditions change, microbes change, and the DNA from microbes can be used to profile total fluid flow (water + oil phases) from benches and between wells. It therefore serves as a powerful tool to provide a range of answers, using advanced analytics and integration with various data sets. In this study, we will provide the background of DNA diagnostics and related analytics, along with the latest insights into viable operating environments. We also highlight recent Permian basin projects that have used DNA in conjunction with operator data to reduce uncertainty about subsurface conditions.
We will show Total Fluid Logs, which are based on comparing DNA signatures from produced fluids with a DNA stratigraphy log. Total Fluid Logs are utilized to 1) constrain interpreted fracture heights, and 2) work in combination with pressure and production data for Rate Transient Analysis (RTA) for significantly improved estimation of the half-length. The case histories will illustrate the differences between production rates and confirmed fracture height and half-length, and a discussion of microseismic is included.
We show how produced fluid collection during pad completions can elucidate well-well communication and demonstrate the impact of completion size and completion order on effective drainage heights. DNA changes in produced fluids can be compared to production data to reveal the timing and impact of frac hits between wells during zipper completions.
Finally, we provide a suggested workflow for analyzing water contributions out of target in the diagnosis of problem wells. Petrophysical logs can be compared to drainage height assessments to help reveal from which depths water may be producing and can be integrated with production data for a more complete subsurface understanding.
DNA diagnostics represent a complementary, cost effective, minimum environmental footprint and low risk tool for operators to easily integrate into existing production and engineering workflows for monitoring well health and subsurface conditions across time.
In the Permian Basin, one of the strategies for reducing cost during hydraulic fracturing operations is to use recycled produced water as the base fluid. The variability in total dissolved solids (TDS) and mineralogy in produced water makes the friction reducer (FR) selection critical in obtaining optimal friction-reduction performance. However, high-TDS FRs tend to be more expensive than freshwater FRs, counteracting the savings obtained by reusing produced water. This paper discusses the implementation of a new anionic slurried FR system in the Delaware basin's Wolfcamp shale. To achieve a cost-effective FR selection, several lab tests were performed, including friction flow loop and water analysis, followed by field trials, in order to design a completion fluid that adjusts to operator needs and water mineralogy/TDS. As a result of this project, a new slurried FR was introduced to the hydraulic fracturing operation that successfully reduced the surface treating pressure, allowing for an increase in treating rate, even at 100% recycled water use. Lower surface pressure also translated to reduced equipment wear and better service quality, a reduction of about 10 minutes per stage reduced pumping time per pad by approximately eight hours. During the field trial, the set point was optimized, giving a maximum FR performance at a fraction of the former FR concentration and a reduction in the overall cost of the operation. A 30% decrease in FR volumes was obtained, resulting in a reduction of the cost for barrel of completion water treated and eliminating an average of one truck load per well, helping to reduce traffic on the congested oilfield routes in the Permian Basin.
One of the main fluid additives in today's hydraulic fracturing completion of unconventional reservoirs is an FR. Its use is governed by the need to achieve the maximum possible treatment rate across a long lateral section, while minimizing surface treating pressure to reduce horsepower use. Additionally, the FR must be cost-effective and be able to perform in the water provided for the completion operation, commonly high TDS produced water.
Abstract Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials. To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy. Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.
Abstract Oilfield water management has become an increasingly critical aspect of oil and gas operations in the United States. With the generational changes in completion techniques making the frac jobs bigger and more resource intensive, proper water management and utilization is key in optimizing operations. At a high level, drought, municipal non-potable sources, produced water volumes, seismicity, SWD capacity, larger frac jobs, capital expense amongst others have drastically increased the considerations for efficient water management. With about 30% of the active North American fleets in the Permian, the issue has become particularly acute regionally. This is driven by the increasing requirements of hydraulic fracturing as an average US well in 2017 used around 9.8 million gallons of water for a frac job. In addition, produced and flowback water from oil and gas wells is an increasing liability for operators in active fields which can create treatment and logistics challenges. The present paper combines data from a wide variety of sources and looks at the dynamic of produced water, frac water and disposed/injected water for operations. It provides a solid mass balance assessment of the water going in and out of the oil field. The paper also overlays several of the known trends to identify opportunities for efficiency gains as well as potential “cost crisis”. This allows for a more robust understanding of economic impact of the water management. Identifying these opportunities, the paper examines formation water chemistry trends and combines them with best practices to provide best practices for water treatment to impact operational efficiencies now as well as projects it in the future. Overall, there is a clear increase in volume of produced water in these major oil producing regions, with the Delaware Basin alone increasing significantly (~80% increment in produced water since 2015) year on year since the emergence of horizontal drilling. The analysis also showed the impact on parallel industries like water midstream infrastructure and logistics development. Cost optimization has driven companies to take on more comprehensive projects with 50% or higher reductions in cost switching from trucking to pipeline.
Ursell, Luke (Biota Technology) | Hale, Michael (Novo Oil & Gas LLC) | Menendez, Eli (Novo Oil & Gas LLC) | Zimmerman, John (Novo Oil & Gas LLC) | Dombroski, Brian (Novo Oil & Gas LLC) | Hoover, Kyle (Novo Oil & Gas LLC) | Everman, Zach (Novo Oil & Gas LLC) | Liu, Joanne (Biota Technology) | Shojaei, Hasan (Biota Technology) | Percak-Dennett, Elizabeth (Biota Technology) | Ishoey, Thomas (Biota Technology)
Abstract Subsurface DNA is an emerging independent diagnostic offering oil and gas operators a high resolution and non-invasive measurement of fluid movement in the subsurface. DNA sequencing methodologies that use subsurface DNA markers acquired from well cuttings and produced fluids are being increasingly used in the Permian Basin to elucidate drainage heights for new and existing wells with increased temporal and spatial resolution. Drainage height estimates are applied across the asset lifecycle during appraisal, development, and production. We present a new exploratory application for DNA Diagnostics in the Midland Basin as a complementary data set for understanding reservoir characteristics when existing wells and data are not available. In this work, Novo Oil and Gas and Biota Technology performed a study on an exploratory well in the Meramec formation of Ector County. Well cuttings were collected from a pilot hole to create a vertical DNA baseline through key Barnett and Meramec formations, and from a lateral section to estimate per stage oil and water contribution. Frac fluid was collected during completion and produced fluids were collected through the initial 189 days of production. A data science-based workflow was performed that tracked DNA markers within produced fluids and compared them to a well-cutting derived DNA baseline to estimate per-formation and per-stage contributions in the vertical and lateral sections, respectively. DNA Diagnostic results were integrated into a reservoir engineering workflow through comparisons with petrophysical logs, core data, geosteering reports, completions reports, production data, and oil tracers. Results showed that initial drainage heights covered a large portion of the Barnett into Woodford formations and corresponded to the higher initial production values. Over time, the DNA drainage heights indicated a focused zone of contribution from the Barnett which corresponded to a steady, flat decline curve. Lateral DNA contributions estimates indicated the highest production contribution from a section of the lateral drilled within the intended landing zone towards the toe, which was corroborated with conventional oil-based chemical tracers. Additionally, the lateral DNA Stratigraphy plots allowed for the development of a hypothesis of a potential fault encountered in the lateral, which subsequent wells will investigate. Overall, we demonstrate that Subsurface DNA Diagnostics provides an independent workflow to estimate drainage height and lateral production allocation by analyzing DNA markers acquired from cuttings and produced fluids. This work shows the complementary nature of incorporating DNA Diagnostics into traditional reservoir engineering workflows as a hypothesis generating tool and as a corroborative measurement. The scalability and non-invasive nature of the workflow has the potential to improve initial characterization and operations during field development, particularly exploratory areas with less operational history. DNA Diagnostics provided direct economic benefit to Novo's field development plan and informed subsequent capital allocation strategies.