Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program

Marine and Petroleum Geology 28 (2011) 295e310

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Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program Robert B. Hunter a, *, Timothy S. Collett b, Ray Boswell c, Brian J. Anderson c, d, Scott A. Digert e, Gordon Pospisil e, Richard Baker c, Micaela Weeks e a

ASRC Energy Services, 3900 C Street, Suite 702, Anchorage, AK 99503, USA US Geological Survey, Denver Federal Center, MS-939, Box 25046, Denver, CO 80225, USA National Energy Technology Laboratory, 3610 Collins Ferry Road, Morgantown, WV 26507, USA d West Virginia University, Department of Chemical Engineering, Morgantown, WV 26506, USA e BP Exploration (Alaska), Inc., P.O. Box 196612, Anchorage, AK 99518-6612, USA b c

a r t i c l e i n f o

a b s t r a c t

Article history: Received 4 November 2009 Received in revised form 19 February 2010 Accepted 26 February 2010 Available online 10 March 2010

The Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled within the Alaska North Slope (ANS) Milne Point Unit (MPU) from February 3 to 19, 2007. The well was conducted as part of a Cooperative Research Agreement (CRA) project co-sponsored since 2001 by BP Exploration (Alaska), Inc. (BPXA) and the U.S. Department of Energy (DOE) in collaboration with the U.S. Geological Survey (USGS) to help determine whether ANS gas hydrate can become a technically and commercially viable gas resource. Early in the effort, regional reservoir characterization and reservoir simulation modeling studies indicated that up to 0.34 trillion cubic meters (tcm; 12 trillion cubic feet, tcf) gas may be technically recoverable from 0.92 tcm (33 tcf) gas-in-place within the Eileen gas hydrate accumulation near industry infrastructure within ANS MPU, Prudhoe Bay Unit (PBU), and Kuparuk River Unit (KRU) areas. To further constrain these estimates and to enable the selection of a test site for further data acquisition, the USGS reprocessed and interpreted MPU 3D seismic data provided by BPXA to delineate 14 prospects containing significant highly-saturated gas hydrate-bearing sand reservoirs. The “Mount Elbert” site was selected to drill a stratigraphic test well to acquire a full suite of wireline log, core, and formation pressure test data. Drilling results and data interpretation confirmed pre-drill predictions and thus increased confidence in both the prospect interpretation methods and in the wider ANS gas hydrate resource estimates. The interpreted data from the Mount Elbert well provide insight into and reduce uncertainty of key gas hydrate-bearing reservoir properties, enable further refinement and validation of the numerical simulation of the production potential of both MPU and broader ANS gas hydrate resources, and help determine viability of potential field sites for future extended term production testing. Drilling and data acquisition operations demonstrated that gas hydrate scientific research programs can be safely, effectively, and efficiently conducted within ANS infrastructure. The program success resulted in a technical team recommendation to project management to drill and complete a long-term production test within the area of existing ANS infrastructure. If approved by stakeholders, this long-term test would build on prior arctic research efforts to better constrain the potential gas rates and volumes that could be produced from gas hydrate-bearing sand reservoirs. Ó 2010 Elsevier Ltd. All rights reserved.

Keywords: Gas hydrate Prudhoe Bay Mount Elbert test well Milne Point Production test

1. Introduction Gas and water combine under favorable pressureetemperature conditions within subsea and onshore arctic sediments to form gas hydrate, a solid that may contain a significant portion of worldwide natural gas resources (Collett, 2002). In 1995, the * Corresponding author. E-mail addresses: [email protected], (R.B. Hunter).

[email protected]

0264-8172/$ e see front matter Ó 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2010.02.015

United States Geological Survey (USGS) conducted the first systematic assessment of the in-place natural gas hydrate resources of the United States (Collett, 1995). That study concluded that permafrost-associated gas hydrates on the Alaska North Slope (ANS) may contain as much as 16.7 trillion cubic meters (TCM; 590 trillion cubic feet; TCF) of in-place gas (Fig. 1). Of this total, up to 2.8 TCM (100 TCF) of in-place gas may be trapped within the gas hydrate-bearing formations of the “Eileen” and “Tarn” gas hydrate accumulations (Collett, 1993) in close proximity to established ANS oil and gas production infrastructure within the Prudhoe Bay

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Fig. 1. Northern Alaska gas hydrate stability zone limit (red outline) from Collett et al. (2008), USGS Fact Sheet 2008-3073. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

Unit (PBU), Kuparuk River Unit (KRU), and Milne Point Unit (MPU) field areas (Fig. 2). However, this probabilistic volumetric assessment did not identify or characterize the nature of individual gas hydrate accumulations or assess the potential for methane recovery. More recent USGS studies reveal a mean estimate of 2.4 TCM (84 TCF) undiscovered, technically recoverable ANS gas hydrate resources (Collett et al., 2008). Historically, ANS gas hydrates have been considered a shallow drilling hazard rather than a potential gas resource. Interpreted occurrence of gas hydrate within Tertiary Sagavanirktok Formation shallow sand reservoirs was originally confirmed by log, core, and

drillstem test (DST) data acquired in the first ANS dedicated gas hydrate test within the Northwest Eileen State-02 (NWE-2) well, drilled in 1972 (Fig. 2; Collett, 1993). NWE-2 DST data suggest limited gas production potential (calculated maximum rate of only 3960 cubic feet/day [CF/d]). Since that time, active investigation of gas hydrate recoverable resource potential has been limited due to no ANS gas export infrastructure, assumed low-rate production potential, unknown production methods, and lack of real-world, field-scale data to validate laboratory experiments and reservoir modeling. However, improved characterization of ANS gas hydratebearing reservoirs, better reservoir simulation of potential gas

Fig. 2. Eileen and Tarn gas hydrate accumulations and ANS field infrastructure (modified after Collett, 1995).

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hydrate dissociation processes, and recognition of large in-place volumes led to increased interest to study the energy resource potential of gas hydrates. Therefore, in collaboration with the USGS, BP Exploration (Alaska), Inc. (BPXA) initiated a cooperative research agreement (CRA) program with the U.S. Department of Energy (DOE) in 2001 to further evaluate whether or not recovery of methane from gas hydrates might become part of the ANS energy resource portfolio. This thematic volume outlines certain program studies, including characterization of gas hydrate-bearing reservoirs; assessment of in-place and potential recoverable resource; development of technologies and approaches to delineate gas hydrate accumulations; refinement of reservoir modeling tools to predict production rates, volumes, and impacts; identification of technical and commercial factors relevant to understanding productivity and future development potential; and selection, preparation, and interpretation of the Mount Elbert field site data acquisition program. This introductory paper reviews significant research and operations results documented in detail in subsequent papers within this Mount Elbert Special Volume. The BPXA-DOE-USGS Mount Elbert-Gas Hydrate Stratigraphic Test well (the Mount Elbert Well) program collected one of the most complete scientific datasets yet assembled on a naturally-occurring gas hydrate accumulation. As discussed in Collett et al. (2009; 2011a), consideration of gas hydrate as a possible economically viable energy resource requires evaluation of the entire petroleum system, including pressure and temperature conditions, gas source, migration, trap, seal, and nature

297

of host reservoir sediments. The “Eileen” gas hydrate accumulation on the ANS (Collett, 1993; Collett et al., 2011a; Wilson et al., 2011) includes a well characterized occurrence of gas hydrates contained within the pore system of sand reservoirs in close proximity to the oil production infrastructure that could help assess the feasibility of production from gas hydrates. Although the technical recovery of gas produced from gas hydrates has only been modeled for the ANS (Anderson et al., 2008, 2011a,b) and proven possible in short-term production testing at the Mallik site in Canada (Dallimore and Collett, 2005; Dallimore et al., 2008a,b; Yamamoto and Dallimore, 2008), the economic viability of gas hydrate production will remain uncertain until sufficient field testing constrains long-term production rates, predicts expected ultimate recovery (EUR) volumes, and defines and implements applicable production technologies. 2. Overview of Mount Elbert Gas Hydrate Stratigraphic Test Well By 2006, geologic and geophysical characterization in combination with reservoir production modeling studies identified key remaining uncertainties related to the resource potential of ANS gas hydrates. At that time, BPXA approved plans to drill the Mount Elbert Gas Hydrate Stratigraphic Test Well (Figs. 2 and 3) within the MPU, operated by BPXA, to acquire data to help mitigate these uncertainties. Drilling and data acquisition operations were conducted from February 5e21, 2007. Program objectives were to

Fig. 3. MPU gas hydrate prospects interpreted from BPXA Milne 3D seismic data.

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acquire geologic and engineering data including whole rock core, logging-while-drilling (LWD), wireline logs, and wireline formation pressure tests. 2.1. Wellsite selection Geologic mapping of the Eileen gas hydrate accumulation within Tertiary Sagavanirktok Formation sands (Collett, 1993) was combined with gas hydrate production and development models (Wilson et al., 2011) to estimate that up to 0.34 TCM (12 tcf) gas may be technically recoverable from the 0.92 TCM (33 tcf) gas-in-place (GIP) within gas hydrate-bearing Sagavanirktok reservoir units E, D, C, B, and A. The USGS successfully applied an integrated geological and geophysical prospecting approach to delineate and characterize discrete MPU gas hydrate accumulations (Lee et al., 2011). The USGS interpretation of the 3D seismic volume provided by BPXA within the context of gas hydrate stability zone pressureetemperature and salinity conditions (Fig. 4) defined by available well logs and water samples as highlighted in Collett et al. (1988) characterized the gas hydrate resource potential of 14 identified sub-permafrost gas hydrate prospects containing an estimated mean 0.019 tcm (0.668 tcf) GIP within the MPU portion of the Eileen accumulation (Figs. 3, 5, and 6; Table 1; Lee et al., 2009, 2011; Inks et al., 2009). The Mount Elbert prospect was selected for drilling and data acquisition after comparative review of these 14 prospects. Interpretation of gas hydrate saturation and thickness were based on integrated analyses of 3D seismic data and existing well log information, using methods similar to those outlined in Lee et al. (2008), which indicated a greater probability of achieving the program data acquisition objectives at this site. The Mount Elbert prospect was interpreted to contain a total 35 m (116 ft) of sand reservoir, highly-saturated with gas hydrate, within units C and D. The geologic risks of the Mount Elbert prospect were substantial, as

this accumulation was interpreted within a previously undrilled area; prior wells drilled and logged in the MPU area did not penetrate significant portions of the seismically mapped gas hydrate prospects and did not contain any gas hydrate-bearing reservoir more than about 6.5 m (20 ft) thick. 2.2. Well planning Extensive pre-well planning, onsite operations vigilance, and the inclusion of gas hydrate well operations and data acquisition experts were key elements to safely drilling and acquiring the Mount Elbert core, log, and wireline formation pressure data (Figs. 7 and 8). In order of importance, the program objectives were to safely acquire wireline log data, whole rock core data, and wireline formation pressure data. The well planning team included gas hydrate, well operations, and planning experts from BPXA, USGS, and DOE National Energy Technology Laboratory (NETL) working with staff from the drilling rig contractor (Doyon), core acquisition company (National Oilwell Varco, formerly ReedHycalog), core handling and analyses company (Weatherford, formerly OMNI), water chemistry and microbiology research group (Oregon State University), wireline log and pressure testing experts (Schlumberger and RPS Energy), and gas geochemistry and physical properties experts (USGS) to plan, assess risk, and recommend risk mitigation to safely accomplish project data acquisition objectives. The Mount Elbert well was drilled vertically to 914 m (3000 ft) as planned from an approximately 120 by 120 m ice pad (Fig. 9). Drilling from a nearby existing gravel production pad would have required a highly deviated well that would have been less suitable for data acquisition. Standard ANS well operations typically install surface casing below both permafrost and gas hydrate-bearing sections within 2e4 days after drilling to help maintain borehole stability and formation integrity. However, in the Mount Elbert wellbore, surface casing would be set above the gas hydrate, but below base-permafrost to protect the permafrost and to facilitate multi-day open-hole data acquisition within gas hydrate-bearing intervals. Use of a mineral oil-based mud (MOBM) drilling fluid coupled with borehole conditioning and good drilling practices provided an in-gauge, stable borehole and enabled meeting these drilling and data acquisition objectives. The MOBM was cooled to approximately
1  C (30  F) in a heat-transfer chilling unit connected to the mud system on the Doyon-14 drilling rig. 2.3. Well drilling and data acquisition operations

Fig. 4. General gas hydrate stability diagram showing approximate combination of pressures and temperatures within which gas hydrate forms a stable compound on the Alaska North Slope.

Fig. 10 shows the enclosed drilling rig, pipeshed, and core processing units on the MPU ice pad location. After setting surface conductor pipe, the surface hole was drilled to 595 m (1952 ft) measured depth (MD) and 24.4 cm (9e5/8-inch) surface casing set. LWD interpretations enabled picking surface casing point by correlating to shallow sections in nearby wells. The LWD tool configuration and bottom-hole-assembly details are provided in Table 2. After setting surface casing, the hole was drilled to “corepoint” of 606.5 m (1990 ft) MD and then cored through base corepoint of 760.1 m (2494 ft) MD as determined from LWD and correlations. The cored interval included a short section of the shale lithologies above the seismically-inferred gas hydrate-bearing reservoir units. The hole was cored using a wireline-retrievable 7.6 cm (3.0-inch) core system with 20.0 cm (7e7/8-inch) bit. The hole was then opened using an 22.2 cm (8e3/4-inch) bit and drilled to a total depth of 914 m (3000 ft) while running only LWD Gamma Ray log. After hole conditioning, four wireline logging runs were conducted (Table 3; Collett et al., 2011b). The hole was again conditioned and cleaned before wireline pressure testing using the

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Fig. 5. Mount Elbert prospect pre-drill seismic-based interpretation of reservoir gas hydrate saturation with WeE and SeN seismic sections across prospect shown in Fig. 6.

Modular Dynamics Testing (MDT) tool in an open-hole environment, which allowed direct measurement of pressure-drawdowninduced dissociation of gas hydrate within the reservoir sediments without potential interference from production casing and associated cement separating the tool from the formation. The sub-permafrost portion of the hole (from 595 m [1952 ft] through total depth [TD] of 914 m [3000 ft]) remained uncased throughout drilling, coring, logging, pressure testing, and data acquisition operations. A contingency 17.8 cm (7-inch) borehole liner was not utilized as excellent hole conditions enabled successful open-hole wireline formation pressure testing and reservoir gas/fluid sampling. The chilled MOBM helped maintain an in-gauge borehole by keeping gas hydrate stable during drilling, coring, logging, and pressure testing operations (Figs. 7 and 8) and successfully eliminated mud system freeze, the need to add salts to a freeze-suppressed water-based drilling mud, and associated borehole erosivity problems (Sigal et al., 2009). 3. Results of Mount Elbert-01 stratigraphic test well The stratigraphic test accomplished all major research objectives. The test acquired all recommended core, log, and formation pressure test data within the predicted gas hydrate-bearing intervals (Fig. 8). These data validated the pre-drill geophysical interpretations by confirming approximately 30 m (100 ft) of combined highly-saturated gas hydrate-bearing sand reservoirs within units

C and D reservoir intervals (Lee and Collett, 2011). The acquired data confirmed and helped further refine the prospecting approach used to identify and assess the MPU gas hydrate prospects and to select the Mount Elbert site for this stratigraphic test (Lee et al., 2011). The acquired geological, geophysical, and geochemical data also help support the theory that the Mount Elbert gas hydratebearing reservoirs likely represent pre-existing gas accumulations that were later converted to gas hydrate by onset of gas hydrate stability conditions associated with permafrost formation (Boswell et al., 2011; Dai et al., 2011; Collett et al., 2011a). Nuclear Magnetic Resonance (NMR) density-derived saturation and other log analyses (Lee and Collett, 2011; Collett et al., 2011b) as well as pore water studies (Torres et al., 2011) indicate gas hydrate saturations in units C and D range from 50 to 75% with a clear linkage to reservoir quality, physical properties, and irreducible water saturation (Boswell et al., 2011; Winters et al., 2011). As predicted, no gas hydrate was detected in units A and B at this site. Table 4 summarizes the average gas hydrate-bearing reservoir properties at the Mount Elbert site that were used in post-drill reservoir modeling studies. 3.1. Core program results Over the 2.5 day coring program, a 153.5 m (505 ft) thick interval was cored in 23 core runs (Rose et al., 2011). A total of 131 m (430 ft) of gas hydrate and water-bearing sediments were recovered,

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Fig. 6. (a) Seismic section WeE through Mount Elbert location showing Unit “C” hydrate events and tie across fault to MPU E-26 with velocity pull-up evident in Staines Tongue units. (b) Seismic section SeN through Mount Elbert location showing Units “D” and “C” hydrate events and tie across fault to MPU B-02.

yielding an 85% core recovery, comparable to core recovered by similar methods in the 2002 Mallik gas hydrate coring operations (Dallimore and Collett, 2005). The wireline system enabled efficient coring and recovery of each core barrel to surface, helping to preserve gas hydrate. Maximum recovery possible per core run was up to 7.3 m (24 ft) plus a few centimeters in the core-catcher. During core retrieval, the core traverses the upper limit of the gas hydrate stability zone at approximately 200 m below surface

(Fig. 4), where gas hydrate-bearing sediment begins to dissociate into gas and water. Therefore, reasonably rapid (20e45 min) processing of core (from wireline retrieval of cored reservoir to surface, to rig floor, to rig pipeshed, and into the core processing units) helped preserve remaining gas hydrate within the core. Onsite description of the core was also completed, which was later supplemented by detailed sedimentology description (Rose et al., 2011). The core was processed onsite and a total of 261

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Table 1 ANS MPU gas hydrate prospect reservoir attributes. Prospect name

Bulk rock volume (m3)

Acres

Porosity

Net to gross

Gas hydrate saturation

Gas-in-place (BCF)

Gas-in-place (billion m3)

Mt. Antero “C” Mt. Bierstadt “D” Mt. Bierstadt “E” Blanca Peak “C” Crestone Peak “C” Mt. Elbert “C” Mt. Elbert “D” Grays Peak “B” Maroon Peak “A” Mt. Princeton “D” Pikes Peak “B” Redcloud Peak “B” Mt. Sneffels “D” Uncompahgre Peak “D” E Combined D Combined C Combined B Combined A Combined

66,545,880 31,704,181 34,891,823 20,977,026 179,796,792 84,961,956 49,876,375 5,771,419 26,261,864 36,580,949 11,261,848 16,580,030 42,949,487 11,056,564 34,891,823 172,167,556 352,281,654 33,613,297 26,261,864

955 268 332 328 1728 1106 267 85 375 449 298 194 516 167 332 1667 4117 577 375

38% 37% 39% 38% 38% 38% 37% 38% 38% 37% 38% 38% 37% 37% 39% 37% 38% 38% 38%

80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80% 80%

66.1% 49.8% 66.9% 55.1% 49.8% 59.7% 52.6% 47.2% 81.2% 53.2% 68.8% 58.1% 57.6% 49.3% 66.9% 52.5% 57.7% 58.03% 81.2%

75.2 32.3 41.8 22.4 185.8 93.3 52 5.8 32.8 38.2 13.2 18 46.2 11.2 41.8 179.9 376.7 37 32.8

2.13 0.91 1.18 0.63 5.26 2.64 1.47 0.16 0.93 1.08 0.37 0.51 1.31 0.32 1.18 5.09 10.7 1.04 0.93

Total

619,216,195

7068

38%

80%

63.3%

668.2

18.9

subsamples were collected. Selected subsamples were processed onsite to extract pore water for both onsite and subsequent laboratory analyses (Torres et al., 2011); to obtain sediment samples for microbiological analyses (Colwell et al., 2011) and physical properties studies (Winters et al., 2011; Dai et al., 2011); and to obtain gas samples for geochemical analyses (Lorenson et al., 2011). In addition, eleven samples from the inferred gas hydrate-bearing

intervals were stored for subsequent analyses, including four preserved in methane-filled pressure vessels and seven preserved in liquid nitrogen (Kneafsey et al., 2011; Lu et al., 2011; Stern et al., 2011). The pressurized samples were later transferred to liquid nitrogen to facilitate shipping to offsite labs. Achieving 85% core recovery provided a significant addition to the stratigraphic, sedimentological (Rose et al., 2011), and

Fig. 7. Mount Elbert log montage with Gamma Ray, Resistivity, gas shows, and mud temperature showing gas hydrate-bearing Sagavanirktok units D and C. The gas show in the lower unit below 2700 ft is associated with a coal interval inferred by low density and low velocity, both not indicative of gas hydrate.

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Fig. 8. Mount Elbert wireline log montage with Gamma Ray, Density, Resistivity, Compressional and Shear Velocity showing gas hydrate-bearing Sagavanirktok units D and C and core interval within Sagavanirktok units D, C, and B.

palynological (Bujak, 2008; Hunter, 2008) record through the ANS shallow nearshore fluvial-deltaic, Tertiary Sagavanirktok Formation sediments which record profound climatic events throughout the Arctic. Pore-scale studies were accomplished on core samples using Cryogenic Scanning Electron Microscope (CSEM), powder X-ray diffraction, and gas chromatography methods to investigate the appearance, grain characteristics, gas composition, and methane isotopic composition of two gas hydrate-bearing core samples. CSEM reveals that over 99% methane gas forms Structure I hydrate as pore-filling material between the sediment grains at approximately 70e75% saturation and sporadically as thin veins typically several tens of microns in diameter (Stern et al., 2011). 3.2. Pore water and gas geochemistry results Coring using the MOBM helped distinguish natural pore waters from drilling fluids, which contained no water. A hydraulic corepress was used during onsite core processing to squeeze pore water from selected core samples. Subsequent pore water analyses used diffusion modeling to explain the anomalous freshening-downward nature of reservoir pore fluids. These analyses, consistent with thermal modeling results, suggest relatively recent modification of the pore fluids associated with the formation of the overlying permafrost section (Torres et al., 2011). Gas geochemistry studies from select core samples confirmed the thermogenic geochemical signature of reservoir gas and sourcing through microbial biodegradation of hydrocarbons associated with deeper conventional oil and gas reservoirs (Lorenson et al., 2011). Associated microbiological studies of select core samples show no clear differentiation of microbiological communities with regard to the in-situ distribution of gas hydrate (Colwell et al., 2011).

3.3. Geomechanical and core preservation results Select core samples were analyzed and suggest that physical strains associated with induced gas hydrate dissociation may be minimal; however, additional analyses are needed on this issue (Dai et al., 2011). Future studies on select frozen reservoir samples in which gas hydrate has been allowed to dissociate are planned to analyze stress and strain; scoping studies suggest that techniques more commonly used in soils labs may provide better data on these unconsolidated sediments. The 11 core samples stored under pressureetemperature conditions supporting the preservation of gas hydrate also enabled detailed study of relative impacts of core handling and preservation procedures. Results suggest that preservation storage of gas hydrate-bearing core within gas-charged pressure vessels will not only preserve primary hydrate, but may also cause secondary hydrate formation (Lu et al., 2011). However, initial preservation via immersion in liquid nitrogen can impart extensive physical disturbance to the sediments (Kneafsey et al., 2011). 3.4. Physical properties analyses results Physical property analyses conducted on the core indicate that gas hydrate occurrence and saturation at Mount Elbert and potentially throughout the ANS is significantly influenced by only slight variations in reservoir properties. For example, it was shown that small reductions in porosity (<4%) correspond to an order of magnitude reduction in intrinsic formation permeability (Winters et al., 2011). These studies also confirm prevailing views that lithology and lithostratigraphically-influenced intrinsic permeability exert primary control on the degree of gas hydrate saturation within porous media.

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Fig. 9. Mount Elbert area surface map areal photo base showing MPU Central Processing Facility, E-Pad, B-Pad, and Mount Elbert ice pad and road.

3.5. Wireline logging program results Obtaining high-quality open-hole wireline logs was a primary data acquisition priority. There were initial difficulties with some of

the logging tools due to cold wellbore temperatures (Table 3). However, a full suite of high-quality open-hole logs were ultimately obtained (Fig. 7, Fig. 8, Table 3). The high quality of the log data is due in large part to maintaining gas hydrate and borehole stability

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Fig. 10. Doyon-14 rig and pipeshed during drilling operations showing core storage (4  4) and processing units.

using chilled MOBM drilling fluids. In addition, the cored hole was “opened” to full diameter following coring and then drilling fluids were circulated to help condition the borehole and facilitate proper mudcake and in-gauge borehole prior to wireline logging. Acquisition of extensive wireline log data enabled comparing the performance and resolution of various log-based methods used to determine gas hydrate saturation (Collett et al., 2011b). The results indicate a high level of confidence in log-based determinations, particularly when gas hydrate saturations are relatively high (greater than 60%; Lee and Collett, 2011; Sun et al., 2011). The maximum gas hydrate saturation of approximately 75% as calculated by the NMRedensity porosity log method and other logs is very similar to the pre-drill seismic interpretation for unit D, but less than the saturations (up to 90%) predicted for unit C (Lee and Collett, 2011; Fig. 5, pre-drill and Fig. 11, post-drill). Analysis of log data in Unit C reveals that complex stratigraphic changes at the base of the unit not included in the pre-drill modeling can account Table 2 Mount Elbert bottom-hole-drilling assembly (BHA) and logging-while-drilling (LWD) configuration. BHA or LWD component

Component length (ft/m)

Cumulative distance from bottom hole (ft/m)

BHA Hughes MXL-1 Bit BHA Bit Sub LWD Resistivity/Gamma Ray LWD Directional LWD Neutron/Density Porosity with Caliper LWD Telemetry Module

1.15/0.35 3.00/0.91 23.53/7.17 9.08/2.77 37.66/11.48

1.15/0.35 4.15/1.26 27.68/8.44 36.76/11.20 74.42/22.68

9.63/2.94

84.05/25.62

for this discrepancy. Further detail on the downhole wireline log data and acquisition program is provided in Collett et al. (2011b).

3.6. Formation pressure testing program results The Mount Elbert Gas Hydrate Stratigraphic Test Well program included acquisition of pressure transient data from open-hole, dual-packer pressure-drawdown tests using Schlumberger’s wireline Modular Dynamics Testing (MDT) tool. Anderson et al. (2011a) explain the detailed planning, acquisition, modeling, and interpretation of these tests. Following coring and wireline logging, these tests were designed to build upon the knowledge gained from cased-hole MDT tests conducted during the Mallik 2002 program (Hancock et al., 2004; Kurihara et al., 2008a,b). A unique aspect of the Mount Elbert program was conducting these experiments in the open hole, which removed many complexities related to the nature and effect of casing perforations. Obtaining these data in an open-hole environment allowed direct measurement of pressuredrawdown-induced dissociation of gas hydrate-bearing sediment without potential interference from production casing and associated cement separating the tool from the formation (Anderson et al., 2011a). In comparison to the Mallik 2002 MDT tests, the individual Mount Elbert tests were of longer duration, with the tests ranging from 6 to nearly 13 h to further enhance data interpretability. Acquisition of this open-hole, dual-packer MDT data confirm earlier results obtained at Mallik (Dallimore and Collett, 2005; Hancock et al., 2004) and indicate ability to technically recover gas from gas hydrates through depressurization (Pooladi-

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Table 3 Mount Elbert-01 logging-while-drilling (LWD) and open-hole (OH) wireline logging programs. Type

Run

Depth (ft)

Depth (m)

Log combination

LWD LWD OH

1e2 3 1

275e1960 1960e3000 1952e2994

84e597 597e914 595e913

OH fail OH fail OH

2 3 4

None None 1952e2944

None None 595e897

OH

5

1952e2996

595e913

OH

6

2000e2648

610e807

OH

7

Various

Various

Drilling Performance; Gamma Ray (GR); EWR-resistivity; neutronedensity porosity LWD GR only Platform Express (PEX); Resistivity with Array Induction (AIT), RtScanner, and ZAIT; Spontaneous Potential (SP); Compensated NeutroneLithoDensity; Electromagnetic Propagation Tool (EPT) MSIP/OBMI: MSIP failed no log data collected DSI/OBMI: DSI failed no log data collected (MSIP replaced with DSI) Dipole Shear Imager (DSI) in expert mode, DSST-P, GPIT, EDCT for GR; Formation MicroImager for oil-based mud (OBMIR); Environmental Measurement Sonde (EMS: PPC1-P) Combinable (or Nuclear) Magnetic Resonance Tool (CMRT-B or NMR) e CMR failed, logged with ECS/HNGC); Natural Spectral Gamma Ray as Hostile Environmental Natural Gamma Ray Spectrometry Cartridge (HNGC); Elemental Capture Sonde (ECS: ECC-A, ECS-A) Combinable Magnetic Resonance Tool (CMR); CMR worked after multiple attempts; Hostile Environmental Natural Gamma Ray Spectrometry Cartridge (HNGC) Modular Dynamics Pressure and Formation Testing (MDT), various depth and time intervals as indicated on Fig. 11

Darvish and Hong, 2011; Anderson et al., 2011a; Kurihara et al., 2011). As shown in Fig. 11, the NMRedensity porosity derived gas hydrate saturation log data were used in the field to assess gas hydrate occurrence and to select appropriate locations for wireline formation pressure surveys (Anderson et al., 2011a). MDT survey intervals were selected to attempt full isolation from adjacent water-bearing zones or other possible reservoir boundaries. Initial MDT operations were conducted within the gas hydrate-bearing intervals to help minimize sand flow and pump wear observed during later stages of testing and in tests attempted within waterbearing intervals (Anderson et al., 2011a). Also, to help identify periods of endothermic gas hydrate dissociation, a small programmable sensor was attached to the outside of the MDT tool in order to monitor temperature changes at the inlet port during each test (Fig. 12). Four 1-m-thick gas hydrate-bearing zones were tested (Fig. 11) with the dual-packer MDT configuration in the Mount Elbert well: two in unit C (tests C1 and C2) and two in unit D (tests D1 and D2). To investigate petrophysical properties of hydrate-bearing reservoirs, an initial pre-flow phase of each MDT test reduced pressure and produced formation fluid without hydrate dissociation (“A” of Fig. 13). Each of the four pre-flow tests was followed by numerous test stages in which the pressure was reduced enough to induce gas hydrate dissociation and monitor pressure buildup after pump shutoff (“B”, “C”, and “D” of Fig. 13). Gas and water samples were collected during selected flow periods (Lorenson et al., 2011) and a fluid analyzer on the MDT tool enabled identification (but not volumetric measurement) of gas and water at the tool intake.

Table 4 Average reservoir properties of gas hydrate-bearing units C and D at Mount Elbert used for reservoir modeling in Anderson et al. (2011b). Reservoir property: reservoir model

Mount Elbert Unit D Problem 7a

Mount Elbert Unit C

Hydrate-bearing reservoir (m/ft, interval in ft) Upper contact Lower contact

14/47 (2014e2061 RKB) Shale contact Shale contact

Average hydrate saturation Average porosity Intrinsic permeability Hydrate-bearing permeability Reservoir temperature (MPU D-02 basis) Hydrostatic pressure Pore water salinity

65% 40% 1000 mD (NMR log) 0.12 mD (MDT model) 2.3e2.6  C

16/52 (2132e2184 RKB) Shale contact Water contact with perched water over hydrate 65% 35% 1000 mD (NMR log) 0.12 mD (MDT model) 3.3e3.9  C

6.7 MPa 5 ppt

7.1 MPa 5 ppt

One pre-dissociation formation water sample was obtained in a single test, which, along with each MDT “pre-flow test”, demonstrated the ability to flow mobile connate formation water from gas hydrate-saturated porous media (Anderson et al., 2011a). Rapid formation cooling was observed at the MDT inlet port during gas hydrate dissociation; both gas flow and dissociation of gas hydrate were demonstrated with pressure drawdown (Fig. 13; Anderson et al., 2011a). In the unit D sand, the mobile water phase was determined to be about 8e10% of total pore volume, and in the unit C sand, it appears to range upward to approximately 15% (Lee and Collett, 2011). Therefore, validating earlier theories and modeling studies (Wilson et al., 2011), these tests indicate that the presence of a mobile water phase appears to be required to initiate depressurization within a gas hydrate reservoir not in contact with underlying free-gas or water reservoirs. The MDT test data from each of the early pre-flow stages that targeted fluid withdrawal without gas hydrate dissociation (“A” of Fig. 13) produced pressure responses that typically indicate lowpermeability porous media, similar to observations of the Mallik 2002 MDT tests. Analyses of these pre-flow tests in a variety of advanced reservoir simulators (Anderson et al., 2011a) have yielded reservoir permeabilities in the presence of a gas hydrate phase of 0.12e0.17 mD. These in-situ permeability estimates confirmed earlier reservoir model estimates (Wilson et al., 2011) and illustrate that non-hydratebearing reservoir permeabilities, which commonly exceed 1000 mD, significantly decrease with increasing hydrate saturations (Winters et al., 2011). This was a key result because in-situ permeability of gas hydrate-bearing sediments is a major uncertainty that could not be adequately addressed by laboratory analyses due to the alteration of natural samples by the acquisition and recovery processes and the unknown relationship between synthetic samples and the natural state of gas hydrate reservoirs (Anderson et al., 2011a). Significantly, these pre-flow tests also demonstrated limited, but functional reservoir fluid (connate water) mobility within even highly gas hydrate-saturated porous media. Gas hydrate dissociation and gas production was confirmed in the latter stages of each test in which the pressure was drawn down below gas hydrate equilibrium conditions (“B”, “C”, and “D” of Fig. 13). Notably, each test resulted in consistent and repeatable pressure response profiles. Detailed analyses of these data (Anderson et al., 2011a) indicate that progressive change in wellbore storage is a key to understanding the reservoir behavior. 3.7. Reservoir modeling results The reservoir data acquired in the Mount Well program enabled reservoir simulation at both field and pore scales. Field-

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Fig. 11. Gas hydrate saturation based on Nuclear Magnetic Resonance (NMR) log for Mount Elbert showing gas hydrate-bearing Sagavanirktok units D and C intervals selected for MDT operations.

scale reservoir simulation models constructed based on Mount Elbert hydrate-bearing reservoir properties determined that for reservoirs with low initial temperatures, wellbore heating applied together with depressurization may increase gas production rates; however, the energy efficiency (amount of

Fig. 12. Sensor capsule micro data logger used to record time, temperature, and pressure during coring and MDT logging operations showing remnants of data logger on right destroyed during operations outside the pressure rating of the capsule.

recovered energy relative to amount of energy expended to extract methane) of thermal stimulation methods is poor (Kurihara et al., 2011). Reservoir simulation clearly identified reservoir temperature as a critical parameter which controls production rate (Anderson et al., 2011b; Moridis et al., 2011). Vertical reservoir heterogeneity, including the presence of thin zones of augmented mobile water, can also profoundly influence total reservoir productivity (Anderson et al., 2011a). Reservoir simulation of a hydrate accumulation based on Mount Elbert hydrate-bearing reservoir properties also demonstrates that high-pressure injection of CO2 would form pore-plugging hydrate, but that injection of CO2 under more moderate injection pressures would prevent formation of pore-plugging secondary gas hydrate. Injection of CO2 into a methane hydrate deposit is thus better enabled by an initial depressurization gas production stage to increase permeabilities of the hydrate-bearing reservoir prior to injection (White et al., 2011). Analyses of MDT data within the International Code Comparison Project (Anderson et al., 2008), enabled by DOE and USGS, helped evaluate and compare multiple gas hydrate numerical modeling codes and confirmed the ability of those codes to estimate gas hydrate production rates through depressurization (Anderson et al., 2011a). Reservoir simulation models indicate that a range of input parameters could reasonably match MDT results. The range of uncertainty in forecasted production rates was narrowed by using MDT data to help quantify modeling of two-phase flow property changes (i.e. variations in permeability) during hydrate dissociation, thus recognizing increasing in-situ permeabilities during hydrate dissociation versus those at initial hydrate saturation conditions (Pooladi-Darvish and Hong, 2011).

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307

Fig. 13. Unit C2 MDT reservoir pressures and temperatures over 11-h test period during reservoir flow, shut-in/build-up, and gas sampling shown with approximate gas hydrate stability pressure during testing. FBHT is flowing bottom-hole temperature and FBHP is flowing bottom-hole pressure. Areas near letters AeD refer to discussion in text.

4. Summary and future implications

acquired critical log, core, and MDT data, which better constrained prior estimates of gas hydrate-bearing reservoir properties used to support pre-drill field development modeling and provided increased confidence in studies that support the potential for future gas production from ANS gas hydrate reservoirs (Wilson et al., 2011). The acquired data also enabled the first detailed complex well and field-scale reservoir modeling efforts of natural gas hydrate-bearing reservoir heterogeneity (Anderson et al., 2011a,b). These studies have also indicated promising gas production potential from thin highquality reservoirs within thicker units (Anderson et al., 2011b). Reservoir simulations also reveal the critical importance of reservoir temperature which would need to be considered

BPXA conducted a comprehensive logging, coring, and well pressure testing program in collaboration with the DOE and USGS at the Mount Elbert location in the MPU on the ANS in February of 2007. Operations proceeded safely, smoothly, ontime, and without incident. Characterization of the MPU gas hydrate accumulations (Lee et al., 2011), combined with the various modeling studies enabled by collection of MDT data at the Mount Elbert site, were key elements helping the USGS to produce its assessment of 2.4 tcm (84 tcf) mean technically recoverable resources from ANS gas hydrates, the first such assessment ever published (Collett et al., 2008). The program

Table 5 Potential future production test site general reservoir properties comparison used in reservoir modeling in Anderson et al. (2011b; after Collett and Boswell, 2009) with corresponding area of Fig. 14. Target unit

Depth, m (ft)

Lower contact

Thickness, m (ft)

Gas hydrate saturation (%)

Milne Point Unit e Mount Elbert prospect (area 1 of Fig. 14) C-sand 650 (2132) Water 16 (52) 65 D-sand 614 (2014) Shale? 14 (47) 65

Porosity (%)

Intrinsic permeability (mD)

Temperature ( C)

Pressure gradient

Salinity (ppt)

35 40

1000 1000

3.3e3.9 2.3e2.6

Hydrostatic Hydrostatic

5 5

Prudhoe Bay Unit e L-V-Z pad vicinity (area 2 of Fig. 14) C2-sand 707 (2318) Shale 19 (62) C1-sand 679 (2226) Shale 17 (56) D-sand 628 (2060) Shale 15 (50) E-sand 584 (1915) Shale 15 (50)

75 75 70 60

40 40

1000 1000 1000 1000

5.0e6.5 5.0e6.5 3.0e4.0 2.0e3.0

Hydrostatic Hydrostatic Hydrostatic Hydrostatic

5 5 5 5

Prudhoe Bay Unit down-dip (area 3 of Fig. 14) 18a (60)a C-sand 762 (2500) Shalea

75a

40a

1000a

w12a

Hydrostatica

5a

40

1000

2.0e3.0

Hydrostatic

5

Kuparuk River Unit e West Sak 24 vicinity (area 4 of Fig. 14) B-sand 689 (2260) Shale? 12 (40) 65 a

Conditions assumed and not well-constrained by adjacent well data for the Prudhoe Bay Unit down-dip site.

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Table 6 Review of risk factors for potential long-term production test sites with area corresponding to Fig. 14. H ¼ high risk associated with this parameter (unfavorable); M ¼ medium risk; L ¼ low risk (after Collett and Boswell, 2009). Field area parameter

MPU E-pad (area 1)

MPU B-pad (area 1)

PBU L-pad (area 2)

PBU Kup St. 3-11-11 (area 2)

PBU down-dip (area 3)

KRU WSak-24 (area 4)

KRU 1H-pad (area 4)

Temperature Ownership Gravel access Geologic Data constraints Well/drilling Facilities Gas handling Water handling Simultaneous operations Operations linkage Multi-zone options

H L M L L LeM L H L L L? MeH

H L M L L LeM L H L M L? MeH

M H L L L M L H L H? M L

M H L L M M M H M L M L

L H H H H H H H H L M MeH

H MeL L M M M M H M L L H

H MeL L M M M L H L H? L? H

Average

LeM

LeM

LeM

M

MeH

M

M

during site selection and operational planning for future production testing. Analyses of log and MDT data confirm occurrence of mobile formation water within reservoirs with high gas hydrate saturations (Lee and Collett, 2011), as well as the ability to mobilize that water through pressure drawdown,

a critical requirement for future depressurization-based production methods (Wilson et al., 2011). The research effort leading up to and including the gas hydrate field program at the Mount Elbert site has significantly contributed to investigations of natural gas hydrate occurrences and assessments of

Fig. 14. Partial Eileen accumulation map showing composite lateral extent of Sagavanirktok gas hydrate-bearing units (Collett, 1993) with four general areas-of-interest for a potential future production test site (see Anderson et al., 2011a, for reservoir model comparison of these areas and Wilson et al., 2011 for individual Sagavanirktok units within this area).

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gas hydrate resource potential. Operationally, the Mount Elbert program clearly demonstrated that a collaborative, scientific evaluation program could be safely and efficiently conducted within the gas hydrate-bearing section on the ANS, allowing a better understanding of the design and potential impacts of future extended field research efforts. The program also featured several operational advances, including the first use of wireline-retrievable coring systems on the ANS and the ability to conduct extended duration, open-hole MDT tests in a gas hydrate-bearing reservoir. The operational and data acquisition priorities for the field program were designed to better constrain critical uncertainties of gas hydrate-bearing reservoir properties used in initial reservoir simulations (Howe et al., 2004) and regional field development modeling (Wilson et al., 2011) and to help assess whether or not gas produced from gas hydrate might someday become part of the broader ANS resource portfolio. The test location was selected based on detailed geologic-geophysical reservoir and fluid characterization and prospecting studies conducted primarily by the USGS (Inks et al., 2009; Lee et al., 2009, 2011) in collaboration with the BPXAeDOE CRA utilizing MPU 3D seismic data provided by BPXA. This field program adhered to BPXA standards for ANS operations and proved the ability to safely conduct drilling and data acquisition operations within ANS gas hydrate-bearing reservoirs. A key element enabling drilling program success was utilization of chilled MOBM drilling fluid, which with proper borehole maintenance and conditioning, helped provide stable and in-gauge hole conditions for data acquisition of continuous wireline core, full wireline log suite, and extended open-hole MDT within interbedded gas hydratebearing and water-bearing intervals. The acquired data were used to calibrate reservoir models, improve recoverable resource estimates, and characterize gas hydrate-bearing reservoir quality, fluid saturations, mobile versus irreducible water content, gas and water chemistry, and microbiology. The Mount Elbert field operations program acquired the first significant Sagavanirktok formation core data within ANS gas hydrate-bearing reservoirs. Studies of acquired data reveal a combined 29.9 m (98 ft) thickness of gas hydrate-bearing sediment (Fig. 8; Lee et al., 2011) within a complex stratigraphic-structural trap within two distinct stratigraphic units C and D (Rose et al., 2011; Boswell et al., 2011). These results conform well to the pre-drill prediction (Lee et al., 2011). The MDT results significantly improved understanding of the in-situ petrophysics of the reservoir and provided insight into reservoir response to local depressurization through free water withdrawal and associated gas production from hydrate dissociation (Anderson et al., 2011a; Pooladi-Darvish and Hong, 2011; Kurihara et al., 2011). Reservoir modeling indicates that the ability of the gas hydrate-bearing porous media to transmit a pressure front could be a key parameter to enable pressure-depletion drive during production testing (Wilson et al., 2011), provided temperatures do not fall below freezing, which would effectively transform the small remaining mobile fluid phase into an immobile ice phase. Reservoir simulations based on an idealized Mount Elbert unit D geologic model (Table 4) have better constrained the range of possible production responses across variable gas hydrate occurrences within the Eileen accumulation and indicate these gas hydrate-bearing reservoirs may be capable of gas production through sustained dissociation by depressurization (Wilson et al., 2011; Anderson 2011a,b; Moridis et al., 2011). These reservoir characterization and modeling techniques have also been applied to identify, compare, and select prospective future production test sites (Collett and Boswell, 2009; Tables 5 and 6 and Fig. 14). The results at Mount Elbert confirm that long-term production testing within the Eileen accumulation infrastructure area (Fig. 14) would better constrain what portion of gas hydrate in-place resources might become a technically-feasible or possibly even a commercial

309

natural gas resource. If approved by stakeholders, a future long-term ANS gas hydrate production test would be designed to build on the successful short-term production test conducted in March 2008 at the Mallik site in the Mackenzie Delta by the governments of Japan and Canada, which indicated the technical feasibility of gas production from gas hydrate by conventional depressurization technology (Dallimore et al., 2008a,b; Kurihara et al., 2008a,b). Although the technical recovery has been modeled for the ANS and proven possible in short-term production testing at the Mallik site, the economic viability of gas hydrate production remains unproven. Additional data acquisition and future long-term production testing could help determine the technical feasibility of depressurization-induced or thermal-, chemical-, and/or mechanical-stimulated dissociation of gas hydrate into producible gas. The results of a future long-term production test might also contribute to the assessment of the resource potential of offshore gas hydrate accumulations in the Gulf of Mexico (GOM) and in other continental shelf areas. Acknowledgements BPXA staff Larry Vendl, Dennis Urban, Dan Kara, Paul Hanson, and others supported stratigraphic test well plans and execution for successful Phase 3a well operations and data acquisition. Seismic and associated reservoir characterization studies accomplished by Tanya Inks (Interpretation Services) and by USGS scientists Myung Lee, Warren Agena, and David Taylor identified multiple MPU gas hydrate prospects. Support by USGS staff Bill Winters, Bill Waite, and Tom Lorenson, NETL staff Kelly Rose and Eilis Rosenbaum, and Oregon State University staff Marta Torres and Rick Colwell is gratefully acknowledged. Peter Weinheber (Schlumberger) helped design the MDT wireline testing program with Steve Hancock (RPS Energy), whom also helped implement this program in the field. Scott Wilson at Ryder Scott Co. progressed reservoir models from studies by the University of Calgary (Dr. Pooladi-Darvish) and the University of Alaska Fairbanks (Dr. Shirish Patil). The MOBM was chilled in a heat-transfer unit operated by DrillCool, Inc. Disclaimer This manuscript was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof nor of BP Exploration (Alaska) Inc. (BPXA). References Anderson, B.J., Wilder, J.W., Kurihara, M., White, M.D., Moridis, G.J., Wilson, S.J., Pooladi-Darvish, M., Masuda, Y., Collett, T.S., Hunter, R.B., Narita, H., Rose, K., Boswell, R., 2008, Analysis of modular dynamic formation test results from the Mount Elbert 01 stratigraphic test well, Milne Point Unit, North Slope, Alaska. In: Proceedings of the 6th International Conference on Gas Hydrates (ICGH 2008), July 6e10, 2008, Vancouver, British Columbia, Canada, 10 pp. Anderson, B., Hancock, S., Wilson, S., Enger, C., Collett, T., Boswell, R., Hunter, R., 2011a. Formation pressure testing at the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: operational summary, history matching, and interpretations. Journal of Marine and Petroleum Geology 28 (2), 478e492.

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