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Energy Strategy Reviews

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Redeveloping depleted hydrocarbon wells in an enhanced geothermalsystem (EGS) for a university campus: Progress report of a real-asset-basedfeasibility study

Ruud Weijermarsa,∗, David Burnettb, David Claridgec, Samuel Noynaerta, Mike Pated,Dan Westphale, Wei Yua, Lihua Zuoa

aHarold Vance Department of Petroleum Engineering, Texas A&M University, 3116 TAMU, College Station, TX, 77843-3116, USAbGlobal Petroleum Research Institute (GPRI), PETE, Texas A&M University, USAc Energy Systems Laboratory (ESL), Department of Mechanical Engineering (MEEN), Texas A&M, USAd Energy Systems Laboratory (ESL), Department of Mechanical Engineering (MEEN), Texas A&M RELLIS Energy Efficiency Laboratory (REEL), MEEN, Texas A&M, USAe ARM Energy, 20329 State Highway 249, Floor 4 Houston, TX, 77070, USA

A R T I C L E I N F O

Keywords:Geothermal energyEGSSpace conditioningWater treatment

A B S T R A C T

A feasibility study is being undertaken at Texas A&M University investigating the concept of using existingwellbores, formerly used for oil and gas production, to provide geothermal space conditioning for the 2000 acreTexas A&M RELLIS Campus. The RELLIS campus is currently constructing its first building and is expected toultimately include approximately 2,000,000 ft2 of education, research and office space. Several horizontalwellbores, originally used for hydrocarbon production, extending beneath the RELLIS campus are no longereconomic and would otherwise be plugged and abandoned if an alternative use were not found. A conversion ofsuch abandoned wellbores for multi-use geothermal energy supply (in a cascaded array of heating, cooling andelectrical power generation) could substantially extend the reach of technically recoverable geothermal re-sources by paving the way for the implementation of a unique large-scale geothermal energy recovery project.This would be one of the first projects in the world to repurpose existing oil and gas wells for large-scalegeothermal use. Much work remains to be done, but this progress report outlines the achievements of the initialassessment completed after the first year of the project study. Beyond providing clean energy, the RELLISCampus geothermal initiative will help find solutions to the issues surrounding non-economic and abandoned oiland gas wellbores, which impact both oil and gas companies and the taxpayers.

1. Introduction

This paper outlines a proposed feasibility study for a large-scaleenhanced geothermal system (EGS) used for space conditioning futurebuildings at the Texas A&M RELLIS Campus. The system would be ableto accommodate the heating and cooling needs for up to 25,000 people.This work is in line with the RELLIS Campus Plan, which includedsustainable and environmentally-friendly design as an important ob-jective in the utility infrastructure design process. The system will useprimarily geothermally heated water from abandoned oil and gas wells,with only minimal amounts of external electric input using an array ofcascading utilities comprised of hot water supply, heating, cooling anddehumidifying units, with optional electrical power supply if excessheat were to remain underutilized. The proximity of the geothermalenergy resource to the infrastructure of the new RELLIS community

offers a significant cost advantage and increases the likelihood of fa-vorable economics for the enhanced geothermal powered space-con-ditioning system. The objective of the planned feasibility study is todevelop and appraise a full-scale development plan for the successfulimplementation of the RELLIS Geothermal Project, using EGS to heatand cool campus buildings. Preliminary engineering estimates indicatethat the existing inactive oil and gas wells tapping the geothermal re-servoir below the campus will likely be able to supply the entire space-conditioning needs of the completed campus.

This paper summarizes insights based on preliminary work done bythe project team to prepare the feasibility study. First we highlightgeothermal capacity currently utilized in the US and geothermal re-source estimations made for 13 US states with identified hydrothermalsystems (Section 2.1). Although Texas lacks such hydrothermal systemswith sufficiently hot water, potential targets for geothermal energy

https://doi.org/10.1016/j.esr.2018.05.005Received 7 December 2017; Received in revised form 12 March 2018; Accepted 31 May 2018

∗ Corresponding author.E-mail address: r.weijermars@tamu.edu (R. Weijermars).

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extraction have been studied since the 1970's (Section 2.2). The RELLISgeothermal project site location, ownership, geothermal rights andregulations are outlined in Section 3. The project design is detailed inSection 4. Direct use of geothermal energy considered in our project isinnovative and comprises the following units: high temperature brinewater conditioning, an absorption cooling system, dehumidificationsystem and Organic Rankine Cycle in a cascading optimized design. Thefeasibility study will evaluate the use of various cascade combinationsof these units to provide air conditioning (cooling/heating) and hotwater supply to future campus buildings. Section 5 briefly discusseshow the RELLIS Geothermal Project would provide a launch pad forgroundbreaking EGS development in the US, comparable to that of theEGS project at Rittershoffen, France, inaugurated June 2016, the onlylarge-scale EGS project currently in existence worldwide. Brief con-clusions are given in Section 6.

2. Geothermal energy in the US

2.1. State-of-the-art

As of 2015, the US has 3.7 GW installed geothermal power capacity,a major fraction of the world's 13.3 GW total, making it by far theworld's leading geothermal energy producer [1]. Fig. 1 shows all of theUS current geothermal power generation capacity (dotted line) is con-fined to just 6 western states (CA, NV, UT, OR, ID, WY). These stateshave crustal sections with relatively high heat flow locally (SMU Geo-thermal Map US, 2004), which in combination with local hydrothermalreservoirs provide favorable conditions for effective heat extraction.The map of Fig. 1 identifies known geothermal sites, commonly mani-fested by natural hot springs, and zones favorable for deep EGS mostlybased on correlation with heat flow rates, resulting in either steeper orshallower geothermal gradients (yellow and red shades, respectively).New Mexico is not included in the core area of states with hydrothermal

energy in Fig. 1, but a new project is currently under construction in theAnimas Valley of southwest New Mexico (Hidalgo County) and isplanned to be in operation in the first quarter of 2019. Cyrq Energy Inc.will operate the field using Organic Rankine Cycle (ORC) turbo-gen-erators supplied by Turboden (owned by Mitsubishi Heavy Industries)exploiting hot brine from existing geothermal wells for the productionof electricity with a name plate capacity of 14 MWe [3]. Wells in theLightning Dock area produce from a 350 to 600 ft deep hot plume re-servoir with well rates ranging from a few hundred gpm to 1200 gpm,typically at 210 to 235° F [4].

Commercially successful extraction of geothermal energy in the USand abroad is only proven for hydrothermal systems. The most recentUSGS resource assessment for power generation potential estimateswith 95% confidence that about 9 GW is available from 240 identifiedhydrothermal systems located in 13 US states (all in western US, plusAlaska and Hawaii [5]. The most optimistic (5% confidence) resourceestimate for these 13 states is 16.5 GW [5].

The USGS geothermal resource assessment only considers energypotential for power generation from identified conventional hydro-thermal systems [6], and does not take into account enhanced geo-thermal systems [7-9]. Further, the USGS methodology only considersrelatively shallow, high-temperature (HT) reservoirs, typically withtemperatures higher than 150 °C in crustal regions with high heat flow[5]. Eastern US states generally have lower geothermal gradients,which means HT geothermal reservoirs can only occur at depths greaterthan in the western US. For example, West Virginia too has HT locationswith over 150 °C rocks at 4.5–5 km depth [10]. Additionally, lowtemperature (LT) geothermal resources could be used for districtheating in colder states [11], a resource potential that is currently notincluded in the USGS geothermal resource estimations.

One of the principal challenges to utilize geothermal resources is toidentify subsurface locations and depths where geothermal fluids mightbe encountered with sufficient enthalpy to support commercially

Fig. 1. Geothermal resource distribution and geothermal resource extraction methods. (a) Geothermal resource map of the United States (adapted from Ref. [2], withthe dotted region outlining the states with primary hydrothermal sites. Color coding classifies favorability to EGS systems.

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successful extraction. For example, hydrothermal power plants becomea viable option when relatively shallow reservoirs will support wellrates of about 3000 gpm with temperatures high enough for either flashpower generators (> 300 °F or 150 °C, so-called HT power plants), ororganic Rankine cycle plants (200–300 °F, so-called LT power plants). Arecent study of the Neil Hot Springs power plant emphasized the needof well productivities of about 3000 gpm or 100,000 bbls/day as aprerequisite for electrical power generation in such geothermal projects[12].

Enhanced geothermal systems (EGS) continue to be studied (FentonHill, US [13]; Rittershoffen, France [14-17]), and new design solutionsmust be developed to render such projects economically viable. Whennative working fluid is lacking or scant, EGS can be developed by in-jecting enough working fluid to contact with the host rock in a hy-draulically fractured geothermal reservoir that lacks native water. Thecost of drilling, completion and fracture treatment of such wells is veryhigh (about $10 million/well), which is why the repurposing of aban-doned hydrocarbon wells with multi-stage frac completions may pro-vide and attractive alternative for geothermal energy extraction fromLT geothermal reservoirs. Working fluid has to be injected and wellproductivities need to be commensurate with the geothermal energyrequired to enable certain cost-saving energy end-user projects. Suchinjection is required because wells in non-hydrothermal regions com-monly do not produce enough native water to sustain any geothermalheat extraction.

2.2. Geothermal energy in Texas and other LT geothermal states

Due to absence of known HT hydrothermal systems, the geothermalresource potential of Texas has not been included in any previous USGS

geothermal resource estimation [5]. In the late 1970s, long before anyshale wells were drilled, the U.S. Department of Energy (DOE) spon-sored an extensive study of the Gulf Coast for geothermal viability. ADOE sponsored pilot project was conducted between 1979 and 1990 ina geo-pressured zone at Pleasant Bayou #2, a Texas well that produced10,000 bbls/day (292 gpm) with BHT of 154 °C (309 °F) and brinesurface temperature of 136 °C (279 °F; see Ref. [18]. Geo-pressuredresources, unlike common hydrothermal resources, commonly containgases like methane [7].

The Pleasant Bayou pilot project (Brazoria, Texas) suggested powergeneration with a binary organic cycle unit was economically viable[19,20]. A 1MW Hybrid Plant operated on a geopressured well atPleasant Bayou in Texas between 1989 and 1990. [19,20]; concludedthat the commercial production of geopressurized geothermal aquifersmay be feasible for certain natural gas and electricity prices (i.e. naturalgas prices of $4.50Mscf and wholesale electricity prices of $0.03 kWh).Flow rates in the geo-pressured zone can vary between 10,000 and40,000 bbls/day [21]. An economic assessment of a small field unitpowered by LT brine suggests these can replace diesel powered gen-erators in remote well locations [22]. A more recent assessment of thegeothermal energy in Texas found there to be just over 1.3×1024 J ofgeothermal resource available in the state, with the largest amountconcentrated along the Gulf Coast [23]. Over the past decade, severaldemonstration projects aimed at extracting geothermal power via co-production from oil and gas wells have been staged with DOE spon-sorship in Texas, Louisiana, Wyoming and North Dakota [24].

Texas has an abundance of oil and gas wells to access geothermalheat. Most wells are actually not completed in the geopressured zone,but in tight formations like the Eagle Ford shale and the Austin Chalk,the latter being naturally fractured. While many oil and gas wells in

Fig. 2. Isotherm maps for East Texas at 6 different depths between 8000 and 13,000 ft, based on well data (adapted from Ref. [10]. The RELLIS Campus is located inBrazos County, adjacent to Grimes County, marked on the 12,000 ft isotherm map.

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Texas will easily reach bottomhole temperatures ranging from LT toHT, the brine production volume also needs to reach a requiredminimum rate. An SMU report [10] gives water production rates ab-stracted from Texas Railroad Commission (RRC) W10 forms, and con-cluded for 2007 only 3 wells (of thousands of wells) produced brinerates of over 6000 bbls/day (175 gpm). Such water rates are near theminimum flow rate necessary for power generation to be even possible(but not necessarily economic) with current binary technology. Thelack of produced water from most regular oil and gas wells can also beinferred from the 2007 reported RRC water disposal and water injectionvolumes per county [10] that were varying between 8087 and 570,000bbls/day; the latter number covering an entire county with probablyconsiderable distance between the individual wells contributing to thecounty totals.

Using the bottomhole temperature of 30,000 wells, a detailed mapof the geothermal potential in East Texas was prepared by a group ofresearchers from SMU, lead by David Blackwell (Fig. 2). Inspection ofthe heat map produced by Ref. [10] suggests temperatures in BrazosCounty (location of Texas A&M University) may reach 300 °F (150 °C)at 12,000 ft depth. However, most oil and gas wells have vertical depthsof 7000 to 9000 ft, targeting Eagle Ford and overlying Austin Chalkformations in certain hydrocarbon maturity windows. EGS by injectionof water and re-circulation in oil and gas wells with expansive fracturesystems in West Virginia was concluded unlikely to be economic atcurrent US electricity prices [11]. Our study will reassess such con-clusions for a specific direct-use project considered for implementationat the Texas A&M RELLIS Campus, where abandoned hydrocarbonwells (∼2.5 km deep) are readily available. The geological map of theRELLIS Campus region is quite uneventful in the sense that the area isvirtually flat and blanketed by Quaternary deposits of the Brazos River.The subsurface formations are all subhorizontal (see Fig. 5, later in thisstudy). Large faults, either recent or from the geological past, have notbeen identified and are precluded to occur in the study area based onrecent wells completed in the Eagle Ford formation. Geo-steering re-ports of three wells in combination with well logging data show perfectin-zone completions within the 20 ft thick landing zone in over 10,000long laterals (proprietary data from operators).

We propose a design that re-engineers arrays of horizontal wells indepleted oil and gas fields to serve as EGS extraction wells. The numberof wellbores in Texas, and the fluids extracted through them from thesubsurface, by far exceeds that of any other state or nation. At the endof 2015, the Texas Rail Road Commission reported 193,807 producingoil wells and 103,526 producing gas wells. Oil and gas extraction volumes,

systematically recorded in Texas only since the 1930's, have reachedastonishing amounts: 61 billion bbls oil (1935–2015) and 71 Tcf naturalgas (1932–2015). A brief author survey of DrillingInfo conducted inAugust 2016 reveals 1800 (active and abandoned) oil and gas wellreports for one county alone (Grimes County). In spite of abundantaccess to the subsurface, no known commercially viable geothermalenergy extraction occurs in Texas as per completion date of our study.

3. Site location, relevant ownership claims, rights and regulations

3.1. RELLIS campus

The Texas A&M RELLIS Campus is a 2000 acre site at the formerBryan Air Force Base, later called the Riverside Campus after decom-missioning, that is under redevelopment to host several strategic in-itiatives and innovation centers. The A&M University System assumedfull title to the site in 1982, and its historic value and future potentialhave been described in the May 2016 vision statement of the RELLISCampus Plans. Development of the site is underway with five new officebuildings scheduled for completion by 2019. The new constructionincludes new headquarters for the Texas A&M Engineering ExperimentStation (TEES) and the Center for Infrastructure Renewal (CIR). The138,000 sq ft CIR facility is scheduled to open in 2018 and the openingof TEES new HQ will follow in 2019. The RELLIS Campus Plan re-commended the entire utility infrastructure be examined with the ob-jective to highlight a model of sustainable and environmentally-friendlydesign. Previously, the A&M main campus achieved significant savingsand environmental foot print reduction with the installation of acombined heat and power (CHP) system with centrally distributedheating and cooling. This prior experience of A&M Utilities and EnergyManagement (UEM) offers a unique opportunity to achieve a similarsuccess at the new RELLIS Campus.

3.2. RELLIS geothermal project plan

The geothermal resource below the RELLIS Campus can be accessedby, and studied using data from ten existing oil wells (Fig. 3). A pre-liminary assessment of the geothermal resource indicates for each 20 ftreservoir thickness of 40 acres accessed by a well, the geothermal en-ergy in place amounts to 2.4×1011 kcal [25]. The target level ofperformance is to establish a working fluid circulation that can bemaintained over at least a 25 year project life-cycle which will extractheat at affordable cost and in sufficient quantities to economically

Fig. 3. Oblique aerial photograph of A&M RELLIS campus with central WWII airfield for orientation. Foreground shows facilities and research buildings and circleshighlight the six well pads, placed peripheral to the campus grounds, from where 10 oil and gas wells have been drilled between 1990s and 2014.

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condition the space temperature of buildings on campus, accounting forall-inclusive cost of the applied subsurface and surface technologies. Apreliminary assessment suggest that 1.2× 109 kcal would be consumedin the planned EGS project, corresponding to a geothermal energy re-covery factor of just 0.5% for the 40 acres/ 20 ft thick reservoir section.The RELLIS lease region is about 2000 acres, which translates to a totalamount of geothermal energy in place for a 20 ft target layer of 1.2 x1013 kcal.

We will collaborate with and use data provided by the well ownerand investigate means to optimize the efficiency of the energy extrac-tion process when redeveloping the existing wells as an enhancedgeothermal system (EGS). Several wells have already been hy-draulically fractured with multi-stage completions and are ideally or-iented to support a loop between injector and producer wells of circu-lating working fluid. The sustainable energy flux that can be extractedfrom the refurbished O&G wells without impairing the geothermal re-servoir will be computed. Based on our subsurface flow models, thefluid circulation can be more precisely directed through the multistagefracture system of the horizontal wells. Our reservoir modeling capacitywill be used to develop a reservoir management plan and heat flowmonitoring system. The daily and seasonal variations in thermal energyrequirements of campus buildings will be integrated into the finalsystem design. A principal metric is levelized cost of space conditioning,based on integration of the available geothermal heat flux units withthe cost of required large-scale space conditioning units. A higher initialcost expenditure may achieve a lower life cycle cost.

3.3. Geothermal permits

We have extensively researched the current ownership of geo-thermal rights and regulations pertinent to the proposed RELLISCampus Geothermal Project. Our present insight is as follows. Thefederal government claims, in accordance with the Federal GeothermalSteam Act of 1970, that it holds geothermal resource ownership onfederal lands, where it holds the mineral estate. The State of TexasGeothermal Resources Act of 1975 states all of the geothermal resource

system components shall be treated as mineral resources. The Act givesthe Texas General Land Office (GLO) the right to lease state land forgeothermal production. In Texas, the regulatory authority of geothermalrights is the Texas Railroad Commission (RRC), in consultation with theGLO and Texas Commission on Environmental Quality (TCEQ). Boththe land on which RELLIS is located and the mineral estate are ownedby the Texas A&M University System. As of today, no geothermal leasehas been granted to any party. The A&M University System administersthe geothermal rights in collaboration with the GLO.

3.4. Working fluid sources and injection

EGS needs massive amounts of water/brine to act as a working fluid.Texas has filed more than 800,000 historical reports for water wellsdrilled in the state (TCEQ website). TCEQ shows 160 water well reportsfor Grimes County, mostly for shallow wells (100–550 ft deep). Asurvey of aquifers in Texas [26] states that (only) the Carrizo-Wilcoxformation carries enough water to allow extraction at rates of up to3000 gpm. An example is provided by Bryan-Texas Utility (BTU) whichlocally produces water from the 2800 ft deep Simsboro sand aquifer inthe Carrizo-Wilcox formation which surfaces with 118 °F [11] (www.BryanTX.gov/water-services/). Hydrostatic pressure brings the waterup to within 200 ft from the ground surface. Pumps are required tobring the water further up to the surface.

Water disposal in Texas commonly occurs in wells in aquifers andzones not identified specifically for EGS purposes. For any injectionwell, the Environmental Protection Agency (EPA) published the finaltechnical regulations for the Underground Injection Control (UIC)program in 1980. In order to give the EPA the authority to regulateunderground injection, the U.S. Congress passed the Safe DrinkingWater Act (SDWA) in 1974 to protect underground drinking watersources (SDWA, Part C, Sections 1421–1426). In 1981, Congress passedamendments to the Safe Drinking Water Act (Section 1425) that al-lowed the delegation of the UIC programs for oil and gas related in-jection wells to a state if the state's program was effective in protectingunderground sources of drinking water (USDWs) and included

Fig. 4. Listed disposal zones as approved for a disposal well in the vicinity of the RELLIS Campus.

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traditional program components such as reporting, oversight, and en-forcement. Between 1981 and 1996, the EPA granted primacy to 34states for all injection wells. A summary of US injection well classifi-cation and associated regulation is given in Appendix A.

In Texas, injection of fluids in the subsurface is regulated by theTexas RRC which issues the permits for injection. For example, several

disposal wells occur in the vicinity of the RELLIS campus, for which theRRC permit (SWR#13, Fig. 4) typically states “This well shall be com-pleted and produced in compliance with applicable special field or statewidespacing and density rules. If this well is to be used for brine mining, un-derground storage of liquid hydrocarbons in salt formations, or undergroundstorage of gas in salt formations, a permit for that specific purpose must be

Fig. 5. a (top): Block diagram showing principal formations and well locations at RELLIS Campus. b (bottom): 3D model of well trajectories below RELLIS Campus.Although all wells appear to be situated in a single landing zone, wells H. M, O, and R were completed in the Eagle Ford and wells 1 to 6 are in the overlying AustinChalk formation. A 3D animation which allows viewing of the well trajectories from various angles of view is provided as Supplementary Material and may bedownloaded from the online version of this article. c: Recorded temperatures in wells from the Eagle Ford landing zone just below the Austin Chalk, crossing Navarroand Austin Chalk formations.

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obtained from Environmental Services prior to construction, including dril-ling, of the well in accordance with Statewide Rules 81, 95, and 97. Thiswell must comply to the new SWR 3.13 requirements concerning the isola-tion of any potential flow zones and zones with corrosive formation fluids.See approved permit for those formations that have been identified for thecounty in which you are drilling the well in.”

Future application for a permit for fluid injection into any RELLISreservoir productive of oil, gas, or geothermal resources (Fluid Injectioninto Productive Reservoirs) is on RRC Forms H-1 and H-1A. TheStatewide Rule 46 describes the application process, notice and op-portunity for hearings, protested applications, special equipment re-quirements (e.g., tubing and packer), and the modification, suspension,or termination of permits for one or more of several causes. Also in-cluded in Statewide Rule 46 are requirements for records maintenance,monitoring and reporting, testing, plugging, and penalties for violationsof the rule. Permit revocation may result as a consequence of non-compliance. RRC form P-4 may need to be filed when a change inOperator occurs moving the well ownership into Texas A&M UniversitySystem's portfolio.

Separately, regulation that applies to any well drilling permit is thatthe Groundwater Advisory Unit in the Oil & Gas Division of the RRCshould issue a groundwater protection determination. For example, forthe Midnight Yell well (Well M) in the Eagle Ford Formation at RELLIS,the RRC issued a Form GW-2 (Groundwater Protection determination)stating that "The base of usable-quality water that must be protected isestimated to occur at a depth of 3500 feet below the land surface. Moreover,

the interval from the land surface to a depth of 1000 feet and the fresh watercontained in the CARRIZO from a depth of 1400 feet to 1750 feet and theSIMBORO from a depth of 2650 feet to 3200 feet must be isolated fromwater in overlying and underlying beds. This recommendation is applicableto all wells within a radius of 500 feet of this location."

4. RELLIS geothermal project design

The principal goal of the RELLIS Geothermal Project is the suc-cessful completion of a real-asset-based feasibility study to de-risk thealready penetrated geothermal resources beneath the 2000 acre RELLIScampus. Such a de-risking requires proving the feasibility of safe andtechnically viable development options in compliance with all regula-tions, while ensuring the economic use of the extracted geothermalenergy with an end-user client in place, prepared to use the offeredenergy system solution.

4.1. Geothermal reservoir verification

The feasibility study will investigate the technical and economicviability of using wells drilled in the Austin Chalk (Fig. 5a), a naturallyfractured carbonate reservoir with an average recorded temperature ofabout 210 °F, for establishing the injection and return flow of heatedbrine. We have subsurface data and historic production from 10 deephydrocarbon wells at RELLIS (Fig. 5b). Exponent Energy, an Oklahoma-based oil and gas company, currently operates 6 wells at the RELLISCampus and supports the geothermal feasibility study through data andaccess to candidate wells. Two inactive wells (Riverside #2 and #5)operated by Exponent Energy are ideally placed to develop solutions forgeothermal circulation. Based on prior work by the current well owner,the wellbores are structurally competent and able to withstand theanticipated stresses from the injection and disposal processes. The localgeothermal gradient is given in Fig. 5c.

At this stage it is not clear whether the two parallel wells are con-nected, if at all, by a single longitudinal fractured system (Fig. 6a,Option 1) or by a series of transverse vertical fractures (Fig. 6b, Option2). If the Austin Chalk models indicate that the formation cannot pro-duce high enough enthalpy to the surface (e.g., [27,28]), two moretarget formations exist which are candidates for injection/productionzones. These formations can be accessed via the same two, currentlyinactive wellbores, but require changing the wellbores over to use ei-ther a shallower zone or a deeper target zone. Using the shallower zone,the Navarro formation, with a recorded temperature of about 160 °F(Fig. 6c, Option 3) is less costly and considerable lower in technical riskthan drilling the deeper Edwards formation (Fig. 6d, Option 4). Al-though the Edwards formation is deeper and costlier to develop, theformation temperature reaches ∼300 °F, which could offset the extracost of well-deepening. All four options shown in Fig. 6a–d) will beevaluated in our study. The Wilcox formation in our area occurs at3630 ft (TVD), contains major aquifers (e.g., Carrizo member) and hastoo low a temperature (∼120 °F) for our purpose.

4.2. Geothermal reservoir model

Heat transfer equations provide temperature profiles for the injectedbrine moving along fracture planes extracting the geothermal energy[29,30]. The model accounts for both the heat transfer process betweenbrine and the fracture walls and heat diffusion inside the fracture wall(cooling caused by the colder brine and heat recovery from the deeperfracture wall). Various software packages exist which could computethe temperature distribution of fluid numerically, such as COMSOLMulti-physics, TOUGH2. Such simulators require long computationtime, and lack some of the versatility of simulations developed formultistage fractured hydrocarbon wells. The inactive horizontal wellsin RELLIS contain mostly some native water but the hydrocarboncomponent cannot be ignored. Saturation of each phase can be

Fig. 5. (continued)

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calculated by means of flash calculations [31,32]. After collecting allthe geophysical data including fracture diagnostics, permeability/por-osity/saturation among others, an advanced geothermal reservoirmodel may be built to simulate the subsurface fluid movement usingthe existing well and fracture placement. The fluid properties may becalculated with Peng-Robinson equation of state [33,34]; to solve thepressure in grid blocks. This model has been applied successfully toseveral similar cases; see our previous work [35,36] for more detail ofthe techniques and applications. The results will then be coupled to theheat transfer module of the reservoir model to calculate the fluidtemperature and flux for the producer well. Additional models forgeothermal heat transfer can be used to determine whether an upscaledEGS process might be technically feasible [37-41]. For a review of

models and applications of heat transfer models in practice, see reviewpapers (e.g., [42]. Methods for geothermal energy harvesting are re-viewed elsewhere [19,43-45]. The option of using deep borehole heatexchangers [46,47] will be considered in our project.

4.3. Produced water management

The principal innovation of the midstream segment is the develop-ment of an energy efficient conditioning loop for the produced waterbetween the downstream wellheads and the upstream heat exchangers.The inputs/outputs connecting all workflows from downstream-mid-stream-upstream are shown in Fig. 7. The midstream team designs theinjection and production wellheads and pumps, with production flow

Fig. 6. A-d: Development Options 1 to 4 (a–d) of Riverside #2 and #5 wells as a geothermal doublet. e) Recorded temperatures in Hullabaloo and Midnight Yell wells(Eagle Ford zone just below the Austin Chalk) crossing Navarro and Austin Chalk formations.

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performance and temperatures conditioned in accordance with the re-servoir capacity and well rates modeled by the subsurface team. Theproduced fluid will be brought with minimum heat loss to the heatexchanger point considering the option of vacuum sealed tubing. Themidstream team design uses a constant flow rate delivery systemthrough the water conditioning subsystem. A self-contained hot watersubsystem for the project is intended to minimize brine scaling andcorrosion in heat pump/recovery systems. In case residual hydro-carbons are inadvertently extracted in the geothermal brine productionloop, a vertical separator unit will be included to collect the hydro-carbons for processing at facilities of adjacent operating wells.

Prior experience has shown that water quality issues were observedin other geothermal projects with efficient heat recovery from hotbrines [48]. For the RELLIS project customized water treatment pilottests are planned utilizing GPRI Designs® on-site water onditioningsystems using hydro-cyclones and micro-filtration process trains. Fieldtrials will validate the GPRI custom filtration subsystem.

4.4. Direct end-use system specification

We estimated the building area to be served by the selected well pairat an average flow rate of 1000 bbl/day. We obtained the thermal en-ergy consumed by groups of A&M Campus Laboratory Buildings,Classroom Buildings and Office Buildings from the campus Utilities andEnergy Services Department (Table 1). Thermal energy from the wellswill be converted to cooling with an average efficiency of 0.6 and heatfrom the wells is used directly to meet the heating needs of the build-ings. Our initial pair of wells with an average flow of 1000 bbl/day ofhot water at 200°F could supply the heating and cooling needs of theamounts of space specified in Table 2, using the amounts of thermalenergy listed in Table 1. Table 2 includes one case with water returnedto the well at 150°F and another case returns the water at 100°F. It is

seen from estimates in Table 2 that a single well-pair can supply thethermal energy needed of a significant building area.

To meet the heating and cooling loads of buildings at RELLIS, hotfluid from the well via an intermediate loop will be used to 1) Heatbuildings, 2) Cool buildings with an absorption system, 3) Dehumidifyoutdoor air with a desiccant system, and 4) Produce electrical/me-chanical power with an Organic Rankine Cycle (ORC). These foursystem categories are commercially available to varying degrees, butwithin a system, category units differ considerably in their applic-ability, size, performance, cost, and thermal fluid requirements (tem-perature), such that a detailed investigation and design analysis needsto be performed to determine their suitability for the project proposal

Fig. 7. Workflow units and process diagram for RELLIS Geothermal Project.

Table 1Consumption of thermal energy for heating and cooling for three buildingtypes.

Bldg. Type # ofBldgs

Total Area (ft2) Cooling (kBtu/ft2-yr)

Heating (kBtu/ft2-yr)

Laboratories 10 1,251,645 241.1 104.5Classroom 7 1,058,274 74.4 24.3Office 7 537,683 50.6 15.6

Table 2Space conditioning capacity estimates.

Building Type Area Supplied w/Return at150°F

Area Supplied w/Return at100°F

Laboratory 12,000 ft2 24,000 ft2

Classroom 41,000 ft2 82,000 ft2

Offices 61,000 ft2 122,000 ft2

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herein. The three systems for cooling, dehumidification, and poweralong with the heating system, can be configured in many arrangementsto optimize their efficiency for utilizing the heat from the brine. Oneexample with the three cooling systems operating in series is shown inFig. 8, where the first system, the absorption cooler (ABS), utilizes thehottest fluid and the last system, the ORC, utilizes the coolest fluid. Alsoshown is the intermediate flow loop that isolates the end-use systemsand equipment from the corrosive brine and a heating coil.

The intermediate flow loop must be designed, sized, and then op-erated so the heating and cooling equipment that interfaces withRELLIS buildings are shielded from the corrosive hot brine (Fig. 8). Thisintermediate flow loop will use water as the working fluid, and bedesigned to minimize the temperature difference between the hot brineand the four major heat-operated systems, using an efficient counter-flow heat exchanger. In addition, downstream of the heat exchanger, anintermediate loop hot-water storage tank will modulate thermal loadsand create thermal capacity. The tank will supply hot water to the threemajor cooling system types and hot water coils to meet the cooling andheating loads of RELLIS buildings. The intermediate loop as describedwill be modeled and analytically evaluated to optimize its design andcomponent arrangements to maximize energy transfer to end-use sys-tems.

An overall surface-system simulation will be developed by com-bining the three heat-operated cooling system models, heating coils and

the intermediate flow loop model. Heating and cooling loads on thesystem will be determined with well-known building energy modelscalibrated to measured data from the Texas A&M campus.Commercially available units will generally be designed for specificapplications and for usage with specific energy sources, such as naturalgas. Therefore, identified units will be further studied and evaluated todetermine if they can be either used “as is” or require modification.Commercial units with promise will be evaluated with focus on per-formance as a function of input temperature and fluid flow rate, usingspecification sheets and performance data. The overall simulation willbe used to size and select component systems and to determine theoptimum arrangement of the three major systems to maximize usage ofwell-water thermal energy. In all, 17 different series and parallel ar-rangements will be investigated as shown in Table 3. The use of thelowest temperature fluid at the low-temperature end of the cascade andin other temperature ranges to provide building heating will also beinvestigated.

Separately, we developed a target setting economic evaluation usinga 20 ton chiller fed by the well [25]. Our initial results indicate that theoriginal utile geothermal energy in-place in the Austin Chalk beneathRELLIS amounts to 239 GWh (107 therms), of which 2.1 GWh (72 ktherms) can be economically recovered over an assumed 25-year plantlife, assuming a target price of 17 cents/kWh for a 0.01MW plant.

Table 3Series cascade and parallel arrangements for heat-operated cooling systems.

Possible cases for 3 systems in series Possible cases 3 systems in two loops

Case Position 1 (highest temperaturesupply fluid)

Position 2 (middleunit)

Position 3 (lowest temperaturereturn fluid)

Case Loop 1 (single unit) Loop 2 (2 units in series)

position 1 (inlet issupply fluid)

Position 1 (inlet issupply fluid)

Position 3 (outlet isreturn flow)

F* ABS ORC DEH L ABS ORC DEHG ABS DEH ORC M ABS DEH ORCH ORC ABS DEH N ORC ABS DEHI ORC DEH ABS O ORC DEH ABSJ DEH ABS ORC P DEH ABS ORCK DEH ORC ABS Q DEH ORC ABS

Note:ABS-Absorption Cooling System,DEH-Dehumidification System,ORC-Organic Ranking Cycle.•Case A is Conventional A/C System.•Case B is loops-each system is supplied individually and directly from the heat source.•Case C is ABS only Case D is ABS and DEH only; Case E is ABS and ORC only.

Fig. 8. Example of a Cascaded Flow Path with all 3 units (see” Case G″ in Table 3).

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5. Discusson

In Europe, earlier research in Soultz-sous-Forêts, France, sponsoredby the EU over several decades, has now lead to the first public-privatepartnership to establish an EGS project at Rittershoffen, France [14-17].The Rittershoffen deep geothermal “power plant” is the first to usesteam from geothermally heated injection water to provide energy to anindustrial site, in this case the Roquette Frères Group in Beinheim.Three partners have formed a joint venture for carrying through theproject, with 40% held by Électricite de Strasbourg (ES, a public uti-lity), 40% by Roquette Frères Group (end-user industry) and 20% bythe Caisse des Dépôts (bank). The production and injection wells areboth located in a deep seated fracture zone, from where hot water isbrought up from a depth of 2500m at a temperature of 170 °C (338 °F).The heat is then removed from the water, which is injected back to thesame source with approximately 1 km horizontal distance between theinjector and production well pair. The hot water enthalpy times pro-duction rate of 70 L/s (1109.5 gpm) gives a designed geothermal poweroutput of 24MWth (MegaWatt Thermal). As the project was only in-augurated in June 2016, the commercial success of the project needsyet to be proven.

Although EGS solutions have been studied in the US since the 1980's(Fenton Hill; [13]), no commercial EGS system currently exists in theUS. Our feasibility study will revisit the geothermal energy potential ofTexas with a particular interest in solutions for geothermal energy re-covery from re-engineered oil and gas well arrays in depleted shalefields. The feasibility study pursued here proposes a redeployment ofsuch wells by re-development into an Enhanced Geothermal System(EGS). New design solutions will be developed to render such projectseconomically viable. Uncertainty will be quantified and together with arisk analysis will provide the necessary information for making in-formed decisions about future implementation of our proposed EGSpowered space-heating system at the Texas A&M RELLIS Campus. Someof the critical success factors in achieving our goals are:

(1) Based on reservoir characterization, target zone identification andthe given data and access to existing wells, develop fluid circulationmodels that extract the heat from the target reservoir(s) with avolumetric flux and temperature suitable for direct use and sus-tainable over the life cycle of the economic project life.

(2) De-risk the geothermal resources by original volume in place esti-mations and recovery factor quantification using advanced geo-thermal reservoir model outcomes and current technology, incombination with regulatory compliant field development options.

(3) Seamless integration of water conditioning subsystems and controlof produced and return water at flux rates and temperatures byappropriate midstream engineering solutions in support of direct-use engineering options (and optimization of such options).

(4) Optimize technology designs that are dimensioned cost-effectivelyaccording to the targeted large-scale end-use, and powered by thegeothermal reservoir with sustainable fluid flux rates and tem-peratures over a minimum 25-year useful project life.

6. Conclusions

EGS projects are in their infancy, and worldwide only one suchlarge-scale project currently exists, namely in Europe at Rittershoffen,France. The successful completion of two wells (one injector and oneproducer) confirmed the temperature forecasts and flow needed forindustrial development. The Rittershoffen Project required the in-stallation of 15 km of fluid transport pipes, comprised of a tube and areturn pipe, buried at a depth of 1.5m to connect the pumping re-injection stations in Rittershoffen with the end-user plant in Beinheim.The pipeline construction work alone took a period of 10 months with acost of about $17 million, which included building tunnels going underthe A35 highway and under the railway line of Strasbourg-Lauterbourg.

The project proposed here aims for a low-cost EGS developmentsolution at the Texas A&M RELLIS Campus, which would be the first ofits kind not only in the US, but worldwide, as oil and gas wells havenever before been refurbished into a full-scale functioning EGS system.Our aim is to establish the feasibility of world's first deep well geo-thermal space-conditioning system for new buildings at the 2000 acre A&M RELLIS Campus. Depleted oil wells may provide economic geo-thermal energy for heating and cooling without additional drilling. Theproximity of the geothermal energy resource to the infrastructure of thenew RELLIS community offers a significant cost advantage and in-creases the likelihood of favorable economics for the EGS - poweredspace-conditioning system. Fluid circulation models will be used todetermine the economic optimum mode for heat extraction strategiesfrom the target reservoir(s). The most efficient processes for production,brine conditioning, and energy conversion from the produced hot waterwill be based on reservoir models. A cascaded combination of heating,cooling, and dehumidification technologies will be evaluated to de-termine the most economic combination to meet the RELLIS campuscooling and heating needs from brine.

Acknowledgements

A fiscal year 2016 Interdisciplinary Seed Grants for Energy Researchwas provided to the lead author by Texas A&M Engineering ExperimentStation (TEES), Dwight Look College of Engineering, and Texas A&MKingsville (TAMUK). Interdisciplinary Seed Grants for Energy Researchaim to foster collaborations among researchers and provides facultywith resources to generate preliminary results for future grant sub-missions. The study is enabled by collaboration of faculty from Texas A&M University Petroleum Engineering and Mechanical EngineeringDepartments with Exponent Energy, an operator of oil and gas wells atthe RELLIS campus.

Appendix A. Classification of Injection Wells

The US Environmental Protection Agency (EPA) classifies under-ground injection wells into five categories: I, II, III, IV, and V. In Texas,the most important category are Class II injection wells, with 31,000active wells, all related to oil and gas activity [49]. There are an ad-ditional 14,000 Class IV injection wells, mostly shallow, used for avariety of non-hazardous fluid injection. A brief review of pertinentregulations and well classes is given below.

A1. Federal versus State control of Underground Class I Injection Wells

Injection of hazardous chemical and steel industry waste started inthe 1950s. During the 1950s, about four wells were reportedly used forhazardous waste disposal. Starting in the mid-1960s through the 1970s,the number of injection wells receiving hazardous waste grew at a rateof more than 20 wells per year [50]. When hazardous waste leakedfrom an abandoned injection well near Hammermill, Pennsylvania inthe early 1970s, the Environmental Protection Agency (EPA) and theState of Pennsylvania tried to use the Clean Water Act to establishregulations to control underground injection. However, the courtsdecided in 1973 that the EPA did not have the authority under theClean Water Act to regulate underground injection. In order to give theEPA the authority to regulate underground injection, the U.S. Congresspassed the Safe Drinking Water Act in 1974 to protect undergrounddrinking water sources (SDWA, Part C, Sections 1421–1426).

EPA published the final technical regulations for the UndergroundInjection Control (UIC) program in 1980. These regulations establishedminimum standards that the state programs needed to meet to receiveprimary enforcement responsibility (or primacy) as allowed under SafeDrinking Water Act (Section 1422). In 1981, Congress passed amend-ments to the Safe Drinking Water Act (Section 1425) that allowed thedelegation of the UIC programs for oil and gas related injection wells to

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a state if the state's program was effective in protecting undergroundsources of drinking water (USDWs) and included traditional programcomponents such as reporting, oversight, and enforcement. Between1981 and 1996, the EPA granted primacy to 34 states for all injectionwells. The EPA directly implements the UIC program in 10 states andshares responsibility in 6 other states. In 1984, the EPA publishedspecial regulations for deep wells injecting hazardous waste as a resultof the Hazardous and Solid Waste Amendments of 1984. In addition tomaking the requirements for these wells more stringent, the regulationsrequire that each well operator demonstrates that the hazardous wastewill not be released from the injection well zone for at least 10,000years or will be rendered non-hazardous by natural processes.

A2. Class I Injection Wells in Texas

EPA Class I wells are designed to inject fluids of hazardous, industrial,and other domestic wastes beneath the lowermost formation containingan underground source of drinking water that lies within 0.25 miles ofthe well bore. The greatest number of non-hazardous wells is in Florida,followed by Texas and Kansas [50]. Currently, there are 473 Class Iinjection wells in the United States, of which 123 are hazardous and350 are non-hazardous or municipal domestic waste wells. Texas has thelargest number of active hazardous wells (64) followed by Louisiana (17)[49]. Typically, Class I injection wells are thousands of feet deep. In theGulf Coast, Class I injection wells can range in depth from 2000 to12,000 feet or more. At these depths, fluids move very slowly, on theorder of a few feet per hundred years or even thousand years [50] andare likely to remain confined for a long period of time. In 1985, about5.1 billion gallons of Class I waste were injected through about 100 dis-posal wells in Texas ([51] p. 5). On average, this amounts to a rate ofabout 100 gpm or 3400 bbl/day per well. The injection rate can be seventimes greater for the most efficient wells ([51]; Table 1). Most operatorsinject in the sandy aquifers along the Gulf Coast, namely the Frio,Yegua, Catahoula, Oakville, Wilcox, and other Miocene sandstones([51]; p. 53). Injection depths range from 2000 to 8500 feet but mostlyfrom 4000 to 7000 feet ([51]; p. 53) primarily against a hydrostaticformation pressure. Normal or hydrostatic pressures have gradients inthe range of 9.8–11 kPa/m (∼0.433 psi/ft).

A3. Class II Injection Wells in Texas

Class II wells are designed to inject fluids that are brought to thesurface in connection with the oil and gas exploration or storage of hydro-carbons. There are approximately 167,000 Class II injection wells in theUnited States. Texas has the largest number of these wells (over 53,000,although only about 31,000 are active), followed by California,Oklahoma, and Kansas. The depths of the injection wells in Texas forpotential disposal of desalination concentrate range from about 250 feetto more than 13,000 feet with an average depth of 4400 feet. More than700,000 acre-feet of high-salinity brines per year are being injectedthrough these wells [49]. Underground injection of wastewater beganin the 1930s when oil companies started disposing oil field brines andother oil and gas waste products into depleted reservoirs. Most of theearly injection wells were oil production wells that were converted towastewater disposal wells.

The physical ability of the oil and gas fields to accept fluids (in-jectivity) has been modeled for six analysis areas by calculating the flowrate that would result from combining the formation physical char-acteristics (porosity, permeability, and compressibility) and pressurerequirements (admissible surface pressure, well depth, and head loss)[49]. The study found that the median injection rate for a single well isonly about 10 gallons per minute (gpm) in the Anadarko, Permian, FortWorth, and Maverick basins. However, the median injection rate wasabout 280 and 470 gpm in the southern Gulf Coast Basin and East TexasBasin, respectively. These rates were expected to increase by screeningmore intervals and stimulating the wells [49].

A4. Class III to Class V Injection Wells

EPA Class III wells are designed to inject fluids into formations forextraction of minerals and solution mining. This includes the mining ofsulfur by the Frasch process, the in-situ production of uranium or othermetals, and solution mining of salts or potash. EPA Class IV wells aredesigned for disposal of hazardous or radioactive wastes. EPA Class Vwells are those not included in the above which are used for numerouspurposes including artificial recharge, cesspools, drainage wells, and heatpump. The [52] estimates that there are currently over 650,000 Class Vinjection wells through the United States. In Texas, there are approxi-mately 14,000 Class V injection wells [53].

Appendix B. Supplementary data

Supplementary data related to this article can be found at http://dx.doi.org/10.1016/j.esr.2018.05.005.

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