Groundwater and Oil and Gas Development: Improved Management Practices for Groundwater Protection and Water Supply: Alphabetical Content Listing
Groundwater Monitoring and Sampling
Measuring Methane in Water Wells - A Tale of Two Methods from Field Screening to Passive Sampling
Kathleen A. Mihm, PG
During an investigation of methane in confined freshwater aquifers ranging from 200 to 800 feet deep, a field screening method has been developed to provide an immediate assessment of methane concentrations in groundwater pumped from water supply wells using an inverted bottle and a field gas monitor. The method can be used to assess safety concerns at a private water supply well prior to receiving laboratory results from water-quality sampling for methane.
For groundwater monitoring wells, a passive sampling method has been developed for wells with methane concentrations that exceed the solubility limit using a discrete interval sampler and dissolved gas sample container. The passive method enables collection of in situ groundwater samples without loss of methane during sample collection and retrieval to the surface. Results from passive sampling, in combination with down hole dissolved gas measurements, suggest that maintaining a sealed borehole is critical for accurate measurements.
Proactive Water Communication by Oil and Gas Operators in the Lochend, Alberta Strike Area
Brent Bowerman, P.Geol.
Alberta’s oil and gas industry prioritizes water resource management through the proactive approach of many industry producers. Baseline Water Resource Inc. (Baseline Water) conducted a regional hydrogeological/hydrological study in the Lochend Industry Producers Group (LIPG) oil and gas operating field northwest of Calgary. This study is an example of how landowner concerns regarding potential water quality/quantity impacts due to hydraulic fracturing can be addressed cooperatively. The objective was to characterize regional hydrogeology and provide a baseline of natural variation in groundwater chemistry. LIPG practices include offering landowners pre-drilling quality and quantity (yield) tests on water wells within 400 metres of hydraulic fracturing activity. The study consisted of 323 water well and 29 spring assessments throughout the LIPG field. Additionally, long term groundwater quality monitoring was performed for a duration of two years coinciding with oil and gas production. Groundwater from the shallow Paskapoo Formation sandstone aquifer is the primary water source for local landowners. Indicators of potential groundwater impacts from oil and gas activity may include elevated chloride and Total Dissolved Solids (TDS) concentrations or the presence of hydrocarbons. The groundwater quality results were comparable to regional background groundwater chemistry and demonstrate natural variation. The data may serve as a baseline for comparison with future water quality analyses. Results of the long-term groundwater quality monitoring indicated no adverse impacts from adjacent oil and gas operations. Study findings were used to prepare communication documents to facilitate water quality discussion between LIPG and private landowners. Stakeholder communication and engagement are paramount to expediting project timelines and improving public perception of the oil and gas industry.
Twenty Five Years of CBM Production and Monitoring of the Pine River Subcrop and Gas Seeps. No Depletion.
Paul Oldaker
Starting in 1994 a ground water, surface water and gas seepage monitoring network was set up in response to observed gas seepage near the subcrop of a producing Coal Bed Methane (CBM) formation and the Pine River in the San Juan Basin, southwestern Colorado. The null hypothesis was that CBM production was releasing gas at the subcrop due to downbasin CBM water pumping. The null hypothesis was tested using down hole video, packer testing, reservoir/seepage production analysis, temperature tracing, cation water quality, water age and potentiometric head trends. Based on the 25 years of observations, measurements and analyses, the CBM null hypothesis was rejected. Since there was no hydraulic connection between the subcrop and CBM production, there was no depletion from the Pine River. A new null hypothesis that gas seepage was due to long term precipitation trends was formulated in 2000 by the author. It continues to be accepted 18 years later. This presentation was awarded a Certificate of Excellence at the 2015 AAPG Annual Convention.
Using Big Data and Small Data (Noble Gases) to Assess the Impact of Shale Gas Drilling on Water Quality
Tao Wen
With recent improvements in high-volume hydraulic fracturing, oil and gas reservoirs with lower permeability are now being tapped. Incidents of water contamination have been reported in some areas of unconventional oil and gas development although the frequency of such incidents appears low.
We have been compiling water quality data from varying shale gas plays across the country by either working with the oil and gas regulator or scraping data from existing databases and publications. We developed new data mining and machine learning techniques to analyze these big datasets of water quality in order to understand the effects of shale gas development. For example, we developed a new ensemble learning model to predict the likelihood of groundwater being impacted by new methane caused by recent shale gas drilling activities.
In the era of big data, case studies based on smaller dataset are indispensable that allow us to investigate closely the problematic areas pointed out by big data studies. Many geochemical tracers have been proposed to indicate the source of contaminant. Among them, noble gases - that are inert and stable - have been undervalued. The heavy noble gases, Krypton and Xenon are of particular value. Noble gas signatures in groundwater and natural gas (both produced gas and stray gas) are controlled by only physical processes. We have applied noble gases, combined with other lines of evidence (e.g., gas and water chemistry), to identify contrasting sources of groundwater contamination in two shale gas plays. One, in Texas, in the Barnett Shale area where the source of contamination is likely natural, the other in the Marcellus Shale area which might have been contaminated by gas migrating from nearby leaking shale gas well(s).
Monitoring Discussion Group
Kathy Butcher
Production Well Monitoring Issues and Methods
A Stable Isotope Ranking Method Useful for Addressing Bradenhead Gas Sources in Legacy Wells, SW Weld County Colorado
Anthony Gorody, Ph. D., P.G.
In advance of directional well development within the Niobrara shale gas resource play, operators are systematically plugging and abandoning vertical legacy wells. Many of these vertical wells have uncemented annular spaces above the Niobrara Formation that can accumulate gases from non-commercial Pierre Shale sand horizons (e.g. Sharon Springs and Sussex Sands). These gases are compositionally distinct from underlying produced gases. Either or both can migrate into bradenheads.
Results of dual inlet mass spectrometer stable isotope analyses show that, for any given stable isotope parameter, both the mean absolute value (MAV) of the difference between sample pairs and the standard deviation (SD) of those differences are similar regardless of gas sample source (lab standard or consecutive production gas samples). This allows statistical ranking of the difference between bradenhead (BHD) and produced (PRD) gas sample pairs from any single well. Each of 8 possible stable isotope parameters in any sample is scored with a value of 1 when |δBHD-δPRD| is less than MAV+3*SD. Totaling the score (maximum of 8 parameters in the methane through pentane range) helps engineers address the source of bradenhead gas.
Data Mining Public Records to Understand the Occurrence of Fugitive Gas Migration in British Columbia, Canada
Elyse Sandl
What can we learn about fugitive methane by conducting statistical analysis of public oil and gas records? In Canada, energy producers are required to report well drilling, completion, production, and abandonment records to the provincial regulators. We are able to access and mine this valuable public dataset to identify well conditions that pose the highest likelihood for fugitive gas migration (GM) in British Columbia, Canada (BC). Presently, GM occurs in 0.6% of the 25,000 oil and gas wells in BC. However, the industry is expected to expand with the construction of an LNG plant opening up Asian markets to Canadian natural gas. Increasing development poses higher risk to groundwater resources and creates an urgency to understand and address the issue of GM. Here we employ multilevel logistic regression to assess the associations between reported occurrences of GM and various well attributes. To account for variation among geological environments and spatial data clustering, the models also assessed variations in effects between regional fields. Preliminary findings suggest that surface casing vent flows and well orientation have the strongest correlations across several fields. Our findings have the potential to help guide GM detection and risk management approaches employed by industry and regulators.
Examining Lateral Gas Migration at Energy Wells - Insights for Risk Management, Monitoring, and Research Directions
Laurie Welch, Ph.D.
Gas migration, the flow of gas outside the surface casing of a well (BC OGC, 2018), is a well integrity issue affecting an estimated <1% up to ~10% of energy wells, depending on geographical region, drilling era, geology, gas source, and other factors (e.g., Davies et al., 2014; Bachu, 2016; Lackey et al., 2017). The risk associated with a given case of gas migration may be defined as the likelihood for gas phase and/or dissolved phase methane to migrate away from a well over a distance to a potential receptor (e.g., a residence or water well), combined with associated potential consequences in relation to human health, safety, and the environment (Welch and Cahill, 2017). All reported cases of gas migration in British Columbia (150 cases, BC OGC, 2018) and Alberta (3276 cases, Bachu, 2017) are based on field observations of surface gas efflux proximal to the wellhead, typically extending radially less than 6 m but up to ~20 m (BC OGC, 2018; Forde et al., 2019). In rarer documented case studies, however, surface gas efflux indicators or water well impacts have been observed at significantly greater distances of 1 km or more (e.g., Chilingar and Endres, 2005; Hammond, 2016). Additionally, recent experimental and numerical modelling work has demonstrated the importance of geologic anisotropy and heterogeneity in influencing gas migration extent (e.g., Cahill et al., 2017; Moortgat et al., 2018). It is, therefore, reasonable to infer there would be a large range in extent of free phase and/or dissolved phase natural gas plumes associated with energy wells exhibiting gas migration. This presentation reviews previous research and data that informs potential lateral gas migration distances for cases of gas migration to examine the likelihood aspect of risk potential. Insights are extracted regarding setbacks, investigation distances, key attributes for assessment, and research needs.
Modeling and Analyzing SCP Data in the Wattenberg Field: Lessons Learned and Best Practices
Greg Lackey
Investigations of stray gas contamination in the Wattenberg Field of Colorado have revealed multiple incidents where faulty oil and gas wells were the pathway for gas migration. Since 2010, the Colorado Oil and Gas Conservation Commission has required operators to submit well integrity tests in the region. These tests, known locally as bradenhead tests, evaluate the outermost annulus of the well for sustained casing pressure (SCP). We collected SCP and well construction data for 3,923 wells in the Wattenberg Field. These data informed two studies: 1) a data analysis study focused on building a framework for identifying high-risk wells and 2) a numerical modeling study in which we simulate SCP buildup behavior. Analytical results demonstrated the value of regional-scale SCP testing. The greatest risk for gas migration was exhibited by wells with short surface casings and a level of SCP greater than the formation fluid pressure at the surface casing bottom. Our modeling results illustrated the relationship between SCP buildup and gas migration. The models can be used to constrain gas fluxes into and out of the annulus and also show the impact of different well construction practices on SCP buildup behavior. In this presentation, we synthesize the findings of these studies to highlight well construction, SCP testing, and SCP management best practices for gas migration prevention. Specifically, we emphasize the need for more frequent, standardized, and comprehensive SCP testing.
Sustained Casing Annular Pressure: Assessment Methods for Gas Migration Investigations
Jeff Kennedy
Sustained Casing Annular Pressure (SCAP) has long been a concern in the oil and gas industry. With the development of unconventional resources, the concern over SCAP has only increased. Unconventional wells present unique challenges in wellbore construction and cementing which have been well documented. Although casing and cementing technologies have improved, these unique challenges often lead to the occurrence of SCAP. While much has been written about wellbore construction and cementing methods to prevent SCAP, there is limited work devoted to assessing SCAP once it occurs. This has led to SCAP analysis and quality control methods which vary throughout the industry. The lack of consistent practices has made interpreting SCAP challenging. This presentation will discuss the significance of SCAP, causes of SCAP, methods for assessing and analyzing SCAP and will provide examples of existing regulatory criteria. Additionally, we will present case studies which illustrate real world SCAP assessment.
Resource Management Discussion Group
Kathy Butcher
Water Resource Management and Protection
Challenges Facing Class II Disposal Well Operations in the Appalachian Basin
Tom Tomastik, CPG
Class II disposal still remains the primary method for disposal of oilfield fluid wastes in the United States. The primary goal of the federal Safe Drinking Water Act and the Underground Injection Control Program to protect the deepest source of underground drinking water and to prevent soil and water contamination.
As a result continued development of oil and natural gas resources from the Marcellus and Utica shales in the Appalachian Basin, the demand for Class II disposal of oilfield fluid wastes has increased significantly. With a small number of Class II disposal wells in West Virginia and lack of primacy in Pennsylvania, only Ohio remains well situated to handle the increase in Class II saltwater disposal well activity in the Appalachian Basin area.
Challenges facing Class II disposal well operations in the Appalachian Basin can be overwhelming. These include: Properly siting disposal wells; ensuring groundwater protection; addressing public and local political opposition; finding geologic formations capable for high capacity disposal operations; developing proper well construction, cementing, and completion methods; selecting the right option for surface facility development and pre-treatment programs; dealing with NORM/TENORM testing and solid waste disposal issues; and developing seismic monitoring and mitigation plans and addressing differing regulatory requirements.
Properly considering of all these challenges will lead to successfully permitting, drilling, constructing, completing, and operating Class II disposal wells in the Appalachian Basin.
Development of a Water Resource Management Plan for An Unconventional Play Discovery
Brian Bohm
The increased reliance on high volume hydraulic fracturing for the development of unconventional oil and gas plays requires exploration and production companies to develop innovative approaches to source and manage water resources. Apache Corporation’s discovery, exploration, and development of the Alpine High field in the Delaware Basin portion of the West Texas Permian Basin provides an example of one company’s approach to water resource management. In late 2015 and 2016, Apache initiate the drilling and completion of the initial discovery wells of what would eventually be known as the Alpine High field. The first wells were drilled and completed using fresh water purchased from local municipalities and water districts, produced water from these wells was trucked to commercial salt water disposal wells. In late 2016, Apache identified the potential scope of development in Alpine High and realized there was a need to transition to non-potable sources of water. By early 2017, Apache had consulted local water resource experts to identify non-potable aquifer systems that could serve as sources of groundwater. In addition to non-potable water, Apache dedicated capital to the construction of a midstream water infrastructure that would allow the company to develop an extensive water recycling program. By the middle of 2017, Apache had drilled three brackish water wells that produced up to 25,000 barrels per day and constructed over 2 million barrels of storage impoundment for both brackish groundwater and produced water. At the end of 2018, Apache has over 400,000 barrels per day of brackish water production capacity and over 8 million barrels of produced water storage that facilitated the company to transition from 100% fresh water sourcing and injection disposal in 2016, to over 90% nonpotable water sourcing and over 85% of produced water being recycled in 2018.
Frac Sand Mining and Its Potential Effects on Groundwater of the Monahans-Mescalero Sand Ecosystem, Permian Basin
Robert E. Mace, Ph.D., PG
Hydraulic fracturing of oil and gas in the Permian Basin requires not only water but also sand, often referred to as frac sand. Up until the end of the last oil and gas boom in 2014, much of the sand used in the Permian Basin was sourced from the upper Midwest, although local supplies of less-ideal Texas Brown Sand from the Brady area began making an appearance. Because transporting sand from the upper Midwest is expensive, constituting upwards of 65 percent of the cost for sand, engineers in the Permian Basin began experimenting with sands local to the Permian Basin and found them suitable to meet their needs at a much lower cost. Furthermore, hydraulic fracturing requires more and more sand per frac well, driving increasing demand for more cost-effective, local sands. These factors, along with recently rising oil prices, have created a boom in local frac-sand mining in the Monahans-Mescalaro Sand Ecosystem. With at least 15 frac-sand mining operations opening since April 2017, 10 of those are in Winkler County alone. Frac-sand mining generally requires water for mining operations, processing and sorting sand, and dust control. Accordingly, frac-sand operations have drilled more than 130 wells into local aquifers to meet their water needs with about half drilling 10 or more production wells per site. Frac-sand mining operations and their associated groundwater use have the potential to affect the habitat of the Dunes Sagebrush Lizard, a species proposed for listing under the Endangered Species Act, as well as local water supplies for ranchers, irrigators, and towns.
Produced Water Disposal in the Artesia Group of the Permian Basin - Feasibility and Effects on Future Water Supplies
Neil Blandford, PG
The study presented in this talk was initiated by an application submitted to the New Mexico Oil Conservation Division (OCD) to replace an existing saltwater disposal well completed in the Seven Rivers Formation of the Artesia Group, and to significantly increase disposal volume. Concerns were raised by a nearby town and the OCD regarding the town’s existing and potential future water supplies, which over- and underlie the zone of proposed injection, respectively. Technical evaluations conducted to predict the fate of injected water include density-dependent groundwater flow and solute transport modeling, and analysis of historical water levels and pumping effects in the Capitan Reef aquifer, which underlies the Artesia Group. Analytical modeling was used to evaluate the most likely source of historical water level increases observed in the Capitan Reef aquifer, and to confirm other observations that indicate minimal hydraulic connection between the injection zone and adjacent aquifers. Although the application was denied and the decision was not appealed by the applicant, the proposed approach is technically feasible and may prove viable as additional data on confining unit thickness and possibly other factors are obtained.
The Need for a Uniform Conservative Definition of Protected Groundwater During Oil and Gas Development
Dominic DiGiulio, Ph.D.
Freshwater shortages in the United States have led to increased use of desalination facilities to treat brackish groundwater for domestic, agricultural, and municipal uses. Groundwater resources are especially important in arid regions experiencing rapid population growth and where surface water rights for irrigation are fully appropriated. Hence, the protection of groundwater resources is necessary, including during oil and gas development. Definitions of protected groundwater are established individually by states. Since, it is both technically and economically feasible to desalinate water having a total dissolved solids (TDS) level of 10,000 mg/L, criteria for an Underground Source of Drinking Water (USDW) is a reasonable standard for the protection of brackish groundwater during oil and gas development. To better understand locations where oil and gas development may be occurring in proximity to USDWs, we examined the United States Geological Survey’s National Produced Waters Geochemical Database. We then reviewed the criteria for protected groundwater in 17 states containing these production wells. In general, we found that definitions of protected groundwater were ambiguous and often did not protect groundwater resources to criteria equivalent to an USDW. This indicates the need for states to protect groundwater to a conservative uniform standard equivalent to that of an USDW to safeguard brackish groundwater for present and future use.
Welcome and Keynote Presentation
Wellbore Barriers--More Than Just a Good Cement Job
Glen Benge
There are many factors to creating effective and resilient wellbore barriers, only one of which is the proper cementing.