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THE I#NIK SIKUMI FIELD EXPERIMENT, ALASKA NORTH SLOPE: DESIGN, OPERATIONS, AND IMPLICATIONS FOR CO2-CH4 EXCHANGE IN GAS HYDRATE RESERVOIRS Ray Boswell, David Schoderbek, Timothy S. Collett, Satoshi Ohtsuki, Mark D White, and Brian J. Anderson Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01909 • Publication Date (Web): 30 Nov 2016 Downloaded from http://pubs.acs.org on December 1, 2016
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THE IĠNIK SIKUMI FIELD EXPERIMENT, ALASKA NORTH SLOPE: DESIGN, OPERATIONS, AND IMPLICATIONS FOR CO2CH4 EXCHANGE IN GAS HYDRATE RESERVOIRS Ray Boswell1*, David Schoderbek2†, Timothy S. Collett3, Satoshi Ohtsuki4, Mark White5, Brian J. Anderson6 1
National Energy Technology Laboratory, Pittsburgh, PA, USA;
[email protected] 2
ConocoPhillips, Anchorage, AK;
3
US Geological Survey, Denver, CO, USA
4
Japan Oil, Gas, and Metals National Corporation, Chiba, JAPAN
5
Pacific Northwest National Laboratory, Richland, WA, USA
6
West Virginia University, Morgantown, WV, USA
ABSTRACT The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas, and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to 1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and 2) observe reservoir response
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upon subsequent flowback in order to assess the potential for CO2 exchange for CH4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2 was likely given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2 and N2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2) flowback conducted at downhole pressures above the stability threshold for native CH4 hydrate; and (3) an extended (30-days) flow back at pressures near, then below, the stability threshold of native CH4-hydrate. The test findings indicate that the formation of a range of mixed-gas hydrates resulted in a net exchange of CO2 for CH4 in the reservoir, although the complexity of the subsurface environment renders the nature, extent and efficiency of the exchange reaction uncertain. The next steps in the evaluation of exchange technology should feature multiple well applications; however, such field test programs will require extensive preparatory experimental and numerical modeling studies and will likely be a secondary priority to further field testing of production through depressurization. Additional insights gained from the field program include: (1) gas hydrate destabilization is self-limiting, dispelling any notion of the potential for uncontrolled destabilization; (2) gas hydrate test wells must be carefully designed to enable rapid remediation of wellbore blockages that will occur during any cessation in operations; (3) sand production during hydrate production likely can be managed through standard engineering controls; and (4) reservoir heat exchange during depressurization was more favorable than expected—mitigating concerns for near-wellbore freezing and enabling consideration of more aggressive pressure reduction. KEYWORDS: Gas hydrate, CO2 Exchange, Alaska North Slope,
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INTRODUCTION Research into the global occurrence of gas hydrate has shown that substantial volumes are likely to exist globally in reservoirs that are amendable to potential commercial natural gas extraction [1]. The details of the production concepts to be ultimately used are yet to be determined, but will likely be based primarily upon destabilization by pressure reduction accomplished with traditional drilling and completion approaches [2, 3]. This depressurization will very likely be supplemented by thermal, mechanical and chemical stimulation as warranted by local conditions. One approach to gas hydrate production involves the injection of CO2, which has been shown in the laboratory to result in the release of CH4 gas from the hydrate lattice in exchange for the CO2 [4]. Chemical exchange using CO2 provides a variety of potential benefits with respect to gas extraction, including the potential sequestration of CO2 in a highly-stable solid hydrate form. Research into the practical applications of CO2-CH4 exchange in hydrates has been conducted in laboratories and through numerical simulation since the mid-1990s. Initial studies, which commonly bathed bulk samples of CH4 hydrate in pure CO2, documented the chemical basis for the exchange process [5, 6, 7, 8]. However, the observed slow reaction kinetics [9] rendered the process a less attractive option for gas hydrate production as compared to depressurization, which showed increasingly positive results in laboratory and field studies [3,10]. Interest in CO2-CH4 exchange was rekindled in the 2000s based upon promising results from a variety of experimental and numerical modeling efforts that focused on exchange potential within a porous-media context [11-13]. These experimental results [14] included (1) relatively rapid CH4 release upon CO2 injection (as much as 50% of the rate observed for
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depressurization in similar samples); (2) exchange of CH4 with CO2 at roughly the theoretical limit (approaching 70%); and (3) a virtually steady-state reaction with no significant water liberation at any time during the process. If such a process could be effectively scaled to an industrial application, methane could potentially be produced through CO2 injection, with a number of clear advantages over existing depressurization-based concepts: 1) reduced water production as the native hydrate-bound water would remain in a solid state; 2) enhanced geomechanical stability associated with the reduced free water influx and increased sediment rigidity through retention of some share of solid hydrate phase; 3) production potential may be less sensitive to initial temperatures than depressurization (where warmer is very clearly better [3]); and 4) potential reduction in the cooling effects of hydrate dissociation, thereby reducing risks of ice formation associated with depressurization-based dissociation. However, while these initial porous-media laboratory experiments appropriately replicated the natural pressure and temperature conditions of gas hydrates on the Alaska North Slope (ANS); the samples synthesized for the studies varied from those expected to occur in nature in two basic ways: 1) the samples were consolidated sandstone, as opposed to the poorly consolidated to unconsolidated sands present in the majority of gas hydrate resource targets; and 2) a lack of any free water in the pore space (which was filled with gas hydrate and free gas only). As data from field programs conducted globally confirmed the common occurrence of free water as the primary constituent of the pore-space not occupied by gas hydrate, additional laboratory experiments were conducted. These attempts to recreate the earlier experimental findings using samples that included free water proved to be extremely challenging, and indicated rapid reduction in, but not total elimination of, effective permeability due to the immediate formation of secondary CO2-hydrate prior to any significant interaction with the native CH4-hydrate [15].
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The Iġnik Sikumi field program was designed to provide insight into the potential commercial viability of exchange-based natural gas production from gas hydrate reservoirs. Although experimental efforts had provided promising findings; further studies to investigate phenomena at larger spatial scales in a laboratory setting was determined not to be feasible. In addition, bench-scale experimental studies utilizing water- and CH4-hydrate-bearing cores were proving to be highly complex and inconclusive. Consequently, it was determined that to evaluate the nature of the exchange reaction, a controlled scientific field experiment was the most effective approach. The overall design was to inject gas as opposed to liquid, as the hydrostatic pressure exerted by a wellbore full of liquid CO2 (early as dense as water at expected subsurface temperatures) was predicted to exceed the mechanical strength of CH4 hydratecemented ANS sandstone reservoirs. Further, it was determined that the most appropriate solution to the problem posed by free water was to design a mixed gas injectant. Following an extensive review of potential ANS field opportunities, the location selected was the vicinity of the Prudhoe Bay Unit (PBU) L-pad [16, 17]. This report will provide details on the nature, design, and findings of the “Iġnik Sikumi (Inupiak for “Fire Ice”) Gas Hydrate Exchange Field Trial”. For further background and information on the Iġnik Sikumi project and the operational details of the field trial, please see [15].
FIELD EXPERIMENT DESIGN AND OPERATIONS The Iġnik Sikumi field experiment was conducted to assess the viability of CO2-CH4 exchange in naturally occurring gas hydrate reservoirs. The program was conducted in the
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Prudhoe Bay Unit (PBU), Alaska North Slope (ANS) (Figure 1) as a short-term “huff and puff” operation with a single injection / production cycle from a single vertical well. The test was conducted in two phases. A single vertical well was drilled, logged, and instrumented in the winter of 2010 and 2011 from a temporary ice pad in close proximity to the PBU L-pad. Activities at the wellsite were then suspended through the summer of 2011. In December 2011, a new ice pad was constructed, the well re-entered, and production testing conducted. Testing operations began in January 2012 and were concluded in May 2012, due to impending spring thaw. The well was then permanently plugged and abandoned. A detailed accounting of field operations can be found in [15]. The following outlines the selection of the test site, the design of the test, drilling and logging operations; well design and instrumentation; test design; and exchange testing operations.
Site Selection A thorough review of available test sites through the ANS was conducted that considered surface access, proximity to needed infrastructure, correspondence to the conditions used in the experimental program (4oC/1000 psi (6.9 MPa), and (most critically) geologic evidence for the occurrence of suitable gas hydrate reservoir targets. Based on these criteria, the search quickly focused on reservoirs below the base of permafrost within the greater Prudhoe Bay region. Using established well-log analysis methods [18], well log data were evaluated for the presence of gas hydrate. As only 1 in 6 ANS wells are logged through the gas hydrate stability zone (GHSZ) with a suite of logs sufficient to confirm the occurrence of gas hydrate, these data were supplemented by review of mud log data for potential gas shows in the target reservoir interval. This review concluded that the most viable site would be in close proximity to the PBU L-pad.
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Geophysical logs in the L-106 well indicated that gas hydrate is present in four separate sandstone units (the “C-2 sand”, the “C-1 sand”, the “D sand”, and the “E sand”) within the Tertiary Sagavanirktok Formation [18] (Figure 2). The Prudhoe Bay Unit L-pad is a permanent gravel pad that hosts over 50 directionally drilled production and injection wells, and sufficient space to conduct hydrate field-trial operations was not available. Selection of the specific site for a temporary ice pad was based on numerical simulations designed to determine a position sufficiently close to the L-106 penetration and to existing roads where 1) faults were not present near the reservoir horizon; 2) the test reservoir would not have been compromised from the heat of existing, producing wellbores; and 3) the planned test would not impact the integrity of surrounding wellbores [16, 17].
2011 Drilling and Logging Operations The primary objectives of the drilling and logging program were to gather field data to more fully characterize the occurrence and nature of gas hydrates at the site, and to enable the final design of the subsequent field trial. Drilling began with installation of a 16” conductor that was set to 110 ft measured depth (MD). Then, 13½” top hole was drilled to 1,482 ft MD. Once surface casing was set to this depth, a 9⅞” hole was drilled to total depth at 2,597 ft MD. The 9⅞” hole was drilled using chilled, oil-based drilling mud to minimize thermal impacts on gas hydrate bearing units during drilling. Logging-while-drilling data, mud log data, cuttings and gas samples were acquired through the full borehole and these and other data are available for public download [19].
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A comprehensive open hole wireline logging suite was acquired in the 9⅞” production test interval including the Platform Express (PEX), Combinable Magnetic Resonance (CMR), Sonic, Pressure Express (XPT), and Modular Formation Dynamics Tester (MDT). Log responses for the gas hydrate reservoir interval indicate good borehole conditions throughout the hydrate-bearing units. Sand-rich units are identified by relatively low gamma-ray readings ( 2 ohm-m) and low compressional-wave transit time (< 140 µsec/ft). The presence of gas hydrate was also inferred by the separation between the conventional density and CMR porosity curves [20]. The data indicated that the hydrate-bearing units observed in the nearby L-106 well [17] were present at this location (Figure 3). The “C-1 sand” (2,243-2,273 ft MD) was selected as the primary testing interval given that it is the highest reservoir-quality zone in the well that is not in direct contact with waterbearing units that could hinder the depressurization needed for the later stages of the flowback operations [21]. The reservoir conditions of the “C-1 sand” include depth to top (2,240 ft), thickness (30 ft or 9.1 m), pressure (1000 psi or 6.9 MPa), temperature (41oF or 5oC), average gas hydrate saturation (72%), and formation breakdown pressure (1450 psi or 10 MPa). The “D sand” was selected as a second option for testing operations; as a result, the well completion was designed to enable a change in testing zone should operational difficulties during the field program so dictate.
Well Design and Instrumentation
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Following log data acquisition, a well completion suitable for conducting the field trial was constructed. The well featured an instrumented casing string that included fiber optic Distributed Temperature Sensor (DTS) cable clamped to the outside and run to TD. Location of the DTS was observable via magnetic signature related to the clamps that allowed the position of the DTS to be avoided during subsequent casing perforation. In order to preserve the “D sand” (at 2,061 ft MD) for potential testing operations, the well production equipment was located at 1,944 ft MD. To allow space for the production equipment, and to enable the slender production well needed to simplify the test, the well featured a tapered casing string that narrowed at 1,974 ft MD (from 7⅝” above to 4 ½” below). This taper divides the well into “upper” and “lower” completions (Figure 4). The lower completion featured three surface-readout pressuretemperature gauges that were attached to the 4½” casing – two above the target reservoir (at 2,034 ft and 2,226 ft) and one below (at 2,285 ft). After perforation, a 38.3 ft (11.7 m)long, 200micron sand screen assembly was installed across the full extent of the “C-1 sand”. The upper completion included a second 4½” casing string that was installed inside the 7⅝” pipe to create a 4½” monobore throughout the full well. Three ¾” tubing strings (a triple “flat-pack”) were clamped onto the inner portion of the upper casing string – two were left open ended to allow glycol/water circulation for the primary purpose of temperature control of the upper completion annulus. The third tubing was connected to a chemical injection mandrel, but was not used during the subsequent testing operations due to suspected tubing failure. The upper completion also included a gas lift mandrel that enabled control of fluid levels within the 4½” tubing as well as the upper annulus (between the 4½” and 7⅝” casings). A reverse jet pump was installed at the gas lift mandrel.
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On May 5, 2011, the completed well was freeze-protected with 9.5 ppg corrosioninhibited 6% KCl brine (lower completion) and 6.8 ppg diesel (upper completion). Throughout the following four months, the re-equilibration from drilling/completion-related warming to ambient temperatures was monitored via the DTS cables encased within the cement between the casing and the sediments (Figure 5).
Test Design The Iġnik Sikumi test design was constrained by the operational conditions: single season operation from a temporary ice pad. In accordance, the program was conducted via injection followed by production within a single vertical well (“huff and puff’). It was recognized that this experimental design is not optimal for potential commercial application of exchange technology, which would likely include field development with separate injectors and producers [22]. Given the time constraints for operations from an ice-pad (limited to winter season), the test design included ~13 days for injection, followed by bottom-hole pressure reduction (via removal of borehole fluids by downhole submersible pumps) to 650 psi (4.49 MPa). This initial phase of pressure reduction would gather reservoir fluids without destabilization of CH4 or CO2 hydrate in the reservoir to allow observations of the impact of the injection. The test would then proceed while time remained to further reduce pressure in a stepwise fashion to the minimal operating limit thereby inducing depressurization-based hydrate destabilization. Given the reservoir minerals are dominantly quartz, no significant mineral dissolution or precipitation was anticipated.
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As originally conceived, the field test was envisioned as a demonstration of “solid-state” CO2 exchange in a system lacking free water. However, as data continued to come available from field programs [10, 23, 24], it became clear that the occurrence of free gas within a hydratebearing unit was unlikely. For example, where gas hydrate saturation (Sgh) was measured to be 70%, the remaining 30% was typically some combination of free water and bound water [25]. In such a system, direct injection of CO2 would be expected to result in rapid CO2-hydrate formation at the injection point and substantial loss of injectivity prior to any substantial interaction between the injected CO2 and the native CH4-hydrate [26]. These expectations were confirmed by further experiments using samples containing only gas hydrate and water that shows substantial but not total loss of permeability upon introduction of CO2 [15], consistent with the concept that most, but not all the free water present in gas hydrate reservoirs is bound water. Considerations of injecting pure CO2 were further complicated by the need to control the phase of the CO2 as gas as the weight of a liquid CO2 column could exceed downhole fracture gradients. To address this challenge, a mixed-gas injectant using CO2 and N2 gas was designed. As expected, this mix successfully addressed both challenges; however, it was recognized that use of a mixed gas would result in a complex geochemical environment that would greatly challenge subsequent interpretation. In particular, no existing numerical simulation codes were available to model the system (or any two-gas injectant process). Nonetheless, it was clear that such a system was necessary to enable CO2 injection. Therefore, to support test design, a simplified model using a multi-cell (“tank to tank”) equilibrium (via MultiflashTM) approach (in both isothermal and adiabatic versions) was developed to bracket the range of reservoir responses to various potential gas mixtures. Prior to design, this approach was benchmarked against results obtained from simulations using the STARSTM model to confirm its suitability.
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Prior laboratory and numerical simulation work suggested that the addition of N2 (commonly investigated in proportions similar to that of power-plant flue gas (80% N2)) to the injected gas mixture could result in more efficient exchange than pure CO2 [8, 26]. Modelling conducted as part of this effort also confirmed that the mixed gas would limit the immediate formation of CO2 hydrate in the near-wellbore region by both displacing free water and altering reservoir geochemical conditions. The concept of a 100% N2 “pre-flush” was investigated and deemed to pose substantial risk of widespread CH4-hydrate dissociation (due to partial pressure effects) that could result in near-wellbore cooling and injectivity loss due to ice formation. Compositions with greater than 60% CO2 were found to be unfavorable due to difficulties in controlling CO2 phase during the change from surface to bottom-hole conditions. Further, compositions of greater than 25% CO2 were found to promote extensive hydrate formation (saturation increases to beyond 90%) in the very near wellbore region. Optimal CO2 content was ultimately determined to be 23%. Injection of chemical tracers (SF6 during the first 6.5 days and HFC114 for the final 6.5 days of injection) was also included to aid interpretation of flowback results. In all modeled N2/CO2 ratios, hydrate formation was predicted to increase at the dissociation front due to a variety of processes, including exchange-related CH4 release and CH4hydrate reformation – however, the modeling suggested that such saturations would likely not exceed 80% (Figure 6). Investigation of optimal injectant volume (“slug size”) found no technical basis for targeting any specific volume. As a result, the test was designed to accommodate volumes expected to be injected during the 13 days allotted for injection in the test program. This volume was estimated at 200,000 scf (5,663 m3).
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2012 Production Testing Operations The primary objectives of the 2012 field program were to demonstrate the ability to inject mixed gas into a gas hydrate-bearing and free water-bearing reservoir, then to produce reservoir fluids by a staged pressure reduction approach that would provide the best opportunity to interpret the nature of reservoir response. The trial proceeded through the following stages (Figure 7): (1) injection (14 days); (2) shut-in soak (2.5 days); (3) unassisted flowback (1.5 days); and (4) jet-pump-assisted flow back (30 days). The jet-pump stage was accomplished in three phases: (1) production at pressures above the destabilization pressure of both native CH4 hydrate and any complex hydrate formed during the injection phase (~9 days); (2) production at conditions in close proximity to the native CH4 hydrate stability (~2.5 days); and (3) production via depressurization at pressures below native CH4 hydrate stability (~18.5 days). The well was never produced at pressures below equilibrium conditions for CO2 hydrate. Injection operations were carefully designed to ensure gas phase at the reservoir level. The total volume of gas injected was 215.9 Mscf (6,113.6 m3): including 167.3 Mscf (4,737.4 m3) N2 and 48.6 Mscf (1,376.2 m3) CO2 for a period of 14 days. Injection pressure was held constant at 1,420 psi (9.8 MPa) and injectant temperature remained within 0.2°F (~0.1oC) of formation temperature. While no “soak” period was planned, operational issues associated with change-over from injection to production resulted in ~4 days of shut-in prior to initiation of flowback. During this time, bottom-hole pressure dropped from 1,420 (9.8 MPa) to 1,200 psi (8.27 MPa). Unassisted flowback continued from ~1.5 days and included gas-only (no water or solids) production to the surface. The initial jet-pump assisted flowback period consisted of 8 days of relatively low and variable gas, water, and solids production at pressures well above those that
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would destabilize native CH4-hydrate (or any mixed-gas hydrate that may have formed during injection). The pressure and temperature measurements within the borehole were also highly variable. Jet-pump assisted flowback (Phase #2) followed two days of shut-in (for repair of equipment) and consisted of high gas production rates (up to 150 Mscf/d (4,247 m3)) and increasing water production rates and continued sand production. This behavior continued for ~3 days at pressures very near the CH4-hydrate stability pressure at reservoir condition. Phase 2 was halted by ice formation in surface tubulars. Jet-pump assisted flowback (Phase #3) followed 5 days of shut in and consisted of 19 days of continuous production at modest but stable and increasing rates. Bottom-hole pressure during this phase was below predicted CH4-hydrate stability conditions.
OBSERVATIONS Reservoir Characterization Log data acquired during the 2011 field program confirmed the occurrence of gas hydrate within four reservoir zones as previously inferred from the nearby L-106 industry well [17]. This report focuses the “C-1 sand” that was the subject of the field testing program. Additional information on the geologic data acquired at the Iġnik Sikumi well throughout the full gas hydrate bearing section are reported in [15, 16, 27]. As no cores were taken during the Iġnik Sikumi field program, determination of the occurrence and habit of gas hydrate is informed solely from log data. The “C-1” sand is a relatively massive and homogeneous sand unit, particularly as compared with the neighboring units. Porosity is ~40% and shale volume is ~20%. Gas hydrate saturation (Sgh) was estimated
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using four standard approaches, Archie’s [28], density-NMR [20], multiple-mineral solution by linear regression [29], and sonic [30]. The first two methods give consistent results with average Sgh of 72%, while the multi-mineral method suggests slightly lower and more variable values (commonly
