Developments in Gas Hydrates - Schlumberger

Developments in Gas Hydrates

Richard Birchwood Jianchun Dai Dianna Shelander Houston, Texas, USA

Gas hydrates—ice-like compounds containing methane—may become a significant

Ray Boswell US Department of Energy National Energy Technology Laboratory Morgantown, West Virginia, USA

hydrate deposits and to map their distribution.

Scott Dallimore Geological Survey of Canada Sidney, British Columbia, Canada Kasumi Fujii Yutaka Imasato Sagamihara, Kanagawa, Japan

Doug Murray Beijing, China Tatsuo Saeki Japan Oil, Gas and Metals National Corporation Chiba City, Chiba, Japan Oilfield Review Spring 2010: 22, no. 1. Copyright © 2010 Schlumberger. For help in preparation of this article, thanks to Barbara Anderson, Brookfield, Connecticut, USA; George Bunge, Houston; Emrys Jones, Chevron, Houston; Tebis Llobet, Yuzhno-Sakhalinsk, Sakhalin, Russia; Yuri Makogon, Texas A&M University, College Station, Texas; and Osamu Osawa, Sagamihara, Japan. CHFR, DMR, EcoScope, geoVISION, MDT, PeriScope, RAB, sonicVISION and TeleScope are marks of Schlumberger.

18

5

Methane gas + ice

10

Methane gas + water

50

Methane hydrate + gas + ice

100

ry nda bou ase s ph

Koji Kusaka Tokyo, Japan

1

-ga rate Hyd

Masafumi Fukuhara Moscow, Russia

Gas hydrate deposits hold copious amounts of hydrocarbon. Estimates range over several orders of magnitude, but the volume of gas contained in gas hydrate accumulations is thought to be more than that in all the world’s known gas reserves. These accumulations often occur in parts of the world that lack conventional reserves, potentially bringing a new level of self-sufficiency to countries that rely on imported oil and gas. The promise of this untapped energy source is prompting several government and industry groups to initiate detailed investigations into developing gas hydrates. In addition to their potential role as an energy source, gas hydrates can present drilling hazards, threaten flow assurance, affect seafloor stability and store or release greenhouse gases. Although these are all important issues, this discussion focuses on the benefits of gas hydrates as a supply of natural gas for future energy needs. This article reviews results of some early hydrate studies and presents the findings of new international efforts that are using advanced technologies to characterize properties and distributions of gas hydrates. Case studies from the Gulf of Mexico, Japan and India demonstrate how oilfield technologies are helping to identify and evaluate gas hydrate accumulations. Examples from Canada and the USA show how natural gas can be produced from these reservoirs.

Ice-water phase boundary

Ann Cook Lamont-Doherty Earth Observatory Earth Institute of Columbia University Palisades, New York, USA

and evaluate conventional oil and gas reserves are being used to characterize gas

Pressure, atm

Timothy Collett US Geological Survey Denver, Colorado, USA

energy resource if ways can be found to exploit them. Techniques designed to find

Methane hydrate + water + gas 500 1,000

–10

0

10

20

30

40

Temperature, °C

> Phase diagram of methane hydrate stability. The methane-water combination is a solid at low temperatures and high pressures (hatched shading). At higher temperatures and lower pressures, solid hydrate dissociates into its gas and water components.

Oilfield Review

H C

H

H

> Gas hydrate crystal structure. Methane [CH4] (green and white) is the guest molecule in a cage formed by water [H2O] molecules (red and white). This structure is one of five types of water cages that contain guest gas molecules. Gas hydrates have been produced from some sites in the Arctic, such as this one in Alaska, USA. (Photograph courtesy of the Mount Elbert gas hydrate stratigraphic test well project.)

Basics of Gas Hydrates Gas hydrates are crystalline solids that resemble ice. Structurally they are clathrates, or compounds in which the basic structure consists of a cage-like crystal of water molecules containing a gas molecule, called a guest (above). Of greatest interest to the energy industry are methane hydrates, which are also the most abundant in nature. Gas hydrates form when sufficient amounts of water and gas are present at the right combination of temperature and pressure (previous page). Outside this stability zone hydrates dissociate into their water and gas components. The

Spring 2010

compact nature of the hydrate structure results in highly efficient packing of methane. A volume of hydrate contains gas that will expand to somewhere between 150 and 180 volumes at standard pressure and temperature. Oilfield Review Spring Chemists have10 known about gas hydrates for Opener more than Hydrates 200 years.Fig. As with many aspects of sciORSPRG10-Hydrate Opener entific discovery, the history of Fig. hydrates is open to debate. However, the earliest formation of hydrate in the laboratory seems to be in 1778 by Joseph Priestley, who inadvertently obtained a hydrate of sulfur dioxide.1 The first documented identification of hydrocarbon hydrates was in 1888 by Paul Villard, who synthesized hydrates of methane and other gaseous hydrocarbons.

H

Throughout the 19th century hydrates were concocted in laboratories and remained mere experimental curiosities without practical applications. It was only after the 1920s—when pipelines began to transport methane from gas fields—that a better understanding of hydrates was required for practical applications. In cold weather, solid plugs would sometimes disrupt gas flow through pipelines. These blockages were at first interpreted to be frozen water. However, in the 1930s the cause of the problems was correctly 1. Makogon YF: Hydrates of Hydrocarbons. Tulsa: PennWell Publishing Co., 1997.

19

Recovered gas hydrates Inferred gas hydrates

> Marine and onshore hydrate locations. About 98% of the gas hydrate resources are concentrated in marine sediments, with the other 2% beneath permafrost. Most of the mapped occurrences of recovered gas hydrates (blue) have been discovered by scientific drilling programs, and the inferred gas hydrate accumulations (orange) have been identified by seismic imaging. [Data from Lorenson TD and Kvenvolden KA: A Global Inventory of Natural Gas Hydrate Occurrence, USGS, http://walrus.wr. usgs.gov/globalhydrate/index.html (accessed March 24, 2010).]

identified as methane hydrates.2 This revelation ushered in a new era of hydrate studies, and investigators developed principles for predicting the formation of hydrates and methods for inhibiting and controlling them.3

In 1946 Russian scientists proposed that the conditions and resources for hydrate generation and stability exist in nature, in areas covered by permafrost.4 This prediction was followed by the discovery of naturally occurring hydrates. In

2. Ziegenhain WT: “Every Precaution Taken to Eliminate 9. Frye M: “Preliminary Evaluation of In-Place Gas Hydrate Clogging of New Chicago Gas Line,” Oil & Gas Journal 30, Resources: Gulf of Mexico Outer Continental Shelf,” no. 19 (1931): 34. OCS Report MMS 2008–004: US Department of the Interior, Minerals Management Service, February 1, 2008. Hammerschmidt EG: “Formation of Gas Hydrates in Natural Gas Transmission Lines,” Industrial & 10. “Gulf of Mexico Gas Hydrates Joint Industry Project Engineering Chemistry 26, no. 8 (1934): 851–855. (JIP) Characterizing Natural Gas Hydrates in the Deep Water Gulf of Mexico—Applications for Safe 3. Carroll J: Natural Gas Hydrates: A Guide for Engineers. Exploration,” National Methane Hydrates R&D Program, Boston, Massachusetts, USA: Elsevier, 2003, http://www. US Department of Energy, http://www.netl.doe.gov/ knovel.com/web/portal/browse/display?_EXT_KNOVEL_ technologies/oil-gas/futuresupply/methanehydrates/ DISPLAY_bookid=1275 (accessed February 27, 2010). projects/DOEProjects/CharHydGOM-41330.html 4. Makogon, reference 1. (accessed February 17, 2010). 5. Miller SL: “Clathrate Hydrates of Air in Antarctic Ice,” 11. The results of the 2005 expedition, for which Science 165, no. 3892 (August 1969): 489–490. donated the seismic data and acquisition, Oilfield Review WesternGeco 6. Riedel M, Hyndman RD, Spence GD, Chapman NR, were published as a thematic set: Ruppel C, Boswell R Novosel I and Edwards N: “Hydrate on the Cascadia Spring 10 and Jones E (eds): Marine and Petroleum Geology 25, Accretionary Margin of North America,” presented Hydrates Fig. 2 no. 9 (November 2008): 819–988. at the AAPG Hedberg Research Conference, 12. “DOE-Sponsored Expedition Confirms Resource-Quality ORSPRG10-Hydrate Fig. 2 September 12–16, 2004, Vancouver, British Columbia, Gas Hydrates in the Gulf of Mexico,” National Methane Canada, http://www.searchanddiscovery.net/documents/ Hydrates R&D Program, US Department of Energy, http:// abstracts/2004hedberg_vancouver/extended/reidel/ www.netl.doe.gov/technologies/oil-gas/FutureSupply/ reidel.htm (accessed February 17, 2010). MethaneHydrates/2009GOMJIP/index.html (accessed 7. Brooks JM, Cox HB, Bryant WR, Kennicutt MC II, February 10, 2010). Mann RG and McDonald TJ: “Association of Gas Shedd B, Godfriaux P, Frye M, Boswell R and Hydrates and Oil Seepage in the Gulf of Mexico,” Hutchinson D: “Occurrence and Variety in Seismic Organic Geochemistry 10, no. 1–3 (1986): 221–234. Expression of the Base of Gas Hydrate Stability in the Reidel M, Collett TS, Malone MJ and Expedition 311 Gulf of Mexico, USA,” Fire in the Ice (Winter 2009): Scientists: “Cascadia Margin Gas Hydrates: Expedition 11–14, http://www.netl.doe.gov/technologies/oil-gas/ 311 of the Riserless Drilling Platform: Balboa, Panama, publications/Hydrates/Newsletter/MHNewswinter09. to Victoria, British Columbia (Canada),” Proceedings of pdf#page=11 (accessed March 23, 2010). the Integrated Ocean Drilling Program, vol 311, http:// 13. Boswell R, Collett T, Frye M, McConnell D, Shedd W, publications.iodp.org/proceedings/311/311title.htm Dufrene R, Godfriaux P, Mrozewski S, Guerin G and Cook A: (accessed March 24, 2010). “Gulf of Mexico Gas Hydrate Joint Industry Project 8. Collett TS, Johnson AH, Knapp CC and Boswell R: Leg II: Technical Summary,” http://www.netl.doe.gov/ “Natural Gas Hydrates: A Review,” in Collett TS, technologies/oil-gas/publications/Hydrates/2009Reports/ Johnson AH, Knapp CC and Boswell R (eds): Natural Gas TechSum.pdf (accessed March 9, 2010). Hydrates—Energy Resource Potential and Associated Geologic Hazards. Tulsa: The American Association of Petroleum Geologists, AAPG Memoir 89 (2010): 146–219.

20

1968 ice cores containing air hydrates were extracted during scientific drilling at Byrd Station in western Antarctica.5 In the 1970s scientists on deepsea drilling expeditions discovered that gas hydrates occur naturally and abundantly in deepwater sediments on outer continental margins. Recently, hydrate masses have been observed on the ocean floor and, in one case, were brought to the surface by fishing net.6 These near-surface concentrations of hydrates in sediments are often associated with gas seeps, also called cold vents, such as those in the Gulf of Mexico and off the Pacific coast of Canada and the USA.7 Scientists now know gas hydrates occur naturally in many parts of the world (left). The typical depth range for hydrate stability lies 100 to 500 m [330 to 1,600 ft] beneath the seafloor. About 98% of these resources are believed to be concentrated in marine sediments, with the other 2% in polar landmasses. Significant accumulations have been identified on the North Slope of Alaska, USA; in the Northwest Territories of Canada; in the Gulf of Mexico; and offshore Japan, India, South Korea and China. Only a small proportion of the evidence for hydrate accumulations comes from direct sampling; most is inferred from other sources, such as seismic reflections, well logs, drilling data and pore-water salinity measurements from cores. Borehole and core data indicate the distribution of hydrates in sediments varies according to the conditions under which they form. Some cores exhibit sparse amounts of hydrates distributed in clay-rich sediments, while others contain intervals of highly concentrated gas hydrate in sandy sediments, and nearly pure, solid gas hydrate has been found as fracture-filling material in clayrich zones. Extrapolating these different scenarios of distribution to all areas where gas hydrates are presumed to occur has led to a tremendous range of potential resource estimates—anywhere from 2.8 × 1015 to 8 × 1018 m3 [9.9 × 1016 to 2.8 × 1020 ft3] of methane globally.8 Narrowing this spread requires advances in several areas: clearer insight into how hydrates are generated and deposited, better understanding of the effects of hydrates on borehole and geophysical measurements, and fuller exploration of areas where conditions for gas hydrate stability exist. The most widespread evidence for accumulations of hydrates offshore comes from seismic data. The potentially strong acoustic impedance contrast between gas hydrate–bearing sediments and adjacent sediments that contain free gas or

Oilfield Review

Alaminos Canyon 3,300

Seafloor

3,400 3,500

Gas hydrate– stability zone

3,600

Two-way time, ms

3,700

BSR

3,800 3,900

JIP Leg I drillsite (2005) JIP Leg II drillsite (2009) Hydrate indicator

4,000 4,100

Amplitude

4,200 4,300

Spring 2010

km

0

150 mi

0

4,400

Green Canyon

150

AT-14

2010 WesternGeco Used by Permission

Atwater Valley

4,500

AC-21 Alaminos Canyon

KC-195 Keathley Canyon

GC-955 WR-313 Walker Ridge

G

fM

o ulf

exi

co

> Seismic section with a bottom-simulating reflector (BSR) from the Gulf of Mexico. A BSR is caused by the acoustic impedance contrast between hydrate-bearing and non-hydrate-bearing sediments. This BSR cuts across layering and a fault and represents the base of the hydrate-stability zone. The reflecting interface separates stiffer material above from less stiff material below, giving rise to a seismic reflection with polarity opposite to that at the seafloor. The high-amplitude signals on the right side of the section probably indicate free gas trapped below the hydrate. The 2005 Gulf of Mexico JIP expedition investigated sites in the Atwater Valley and Keathley Canyon areas. In 2009 JIP scientists drilled and logged boreholes in Alaminos Canyon, Walker Ridge and Green Canyon. Geophysical indicators of the base of the hydrate-stability zone are shown in red on the inset map. (Map adapted from Shedd et al, reference 12; seismic section courtesy of WesternGeco.)

Walker Ridge Block 313 NW

SE

A nB

on

3,400

Ho

Ho

rizo

3,350

3,450 3,500

Two-way time, ms

Gulf of Mexico Hydrate Assessment The Minerals Management Service (MMS) of the US Department of the Interior has used seismic data, along with wellbore, geologic, geochemical and paleontological information, to assess large areas of the Gulf of Mexico—about 174,000 mi2 [450,000 km2]—where pressure and temperature conditions are suitable for hydrate-stability conditions.9 The MMS study estimates the total in-place volume of biogenically generated gas hydrates ranges from 11,112 to 34,423 Tcf [315 to 975 trillion m3]. In 2000 Chevron and the US Department of Energy initiated a JIP to develop technology and acquire data to help characterize naturally occurring gas hydrates in the deepwater Gulf of Mexico.10 In addition to assessing the impact of hydrates on drilling safety and seafloor stability, the project strives to understand the long-term potential of hydrates as a supply of natural gas. In the early phases of the project, JIP team members acquired and analyzed seismic data, selected drilling locations and conducted a 35-day drilling, coring and logging expedition covering several sites.11 In 2009 the JIP conducted a second expedition, which included sites in the Walker Ridge and Green Canyon areas.12 Borehole locations were selected based on an integrated geologic and geophysical analysis of indicators for the presence of gas hydrates at high saturations within sand reservoirs (above right). The JIP program in the Gulf of Mexico has provided substantial information on gas hydrate exploration and drilling hazard assessment. Gas hydrate exploration—An example of a hydrate indicator in the Walker Ridge area is the discontinuous high-amplitude reflection that corresponds to the updip terminations of free gas in sandstones (right). The high amplitudes track the base of the hydrate-stability zone.13

New Orleans

riz

water can cause a high-amplitude reflection. The reflection depth depends on the temperature and pressure conditions conducive to hydrate stability; typically, it parallels the seafloor. Such interfaces are known as bottom-simulating reflectors (BSRs), and the seismic reflections they cause often cut across structural and stratigraphic reflections. However, lack of a BSR does not preclude the presence of hydrates. The discovery of BSRs in many parts of the world has led government agencies, energy companies and other institutions to form collaborative ventures to assess particular hydrate accumulations. One such joint industry project (JIP) is investigating hydrates in the Gulf of Mexico.

3,550 3,600 3,650

Base of gas hydrate stability

Oilfield Review Spring 10 Hydrates Fig. 3/4 ORSPRG10-Hydrate Fig. 3/4

3,700 3,750 3,800 3,850

Amplitude  2010 WesternGeco Used by Permission

3,900

> Seismic data from Walker Ridge Block 313, Gulf of Mexico. The seismic section shows a series of isolated high-amplitude spots (blue and red) that delineate the base of the hydrate-stability zone. The high-amplitude reflections are discontinuous in this view because the layers have varying lithology and are steeply dipping. Free gas and gas hydrates are concentrated in the sand-rich layers. Because shale-rich layers contain little or no hydrate, they do not exhibit significant amplitudes. Horizons A and B are discussed in a later figure. (Courtesy of WesternGeco.)

21

Cement at Contacts M1

Grain Coating

5.5

M2

5.0

Supporting Matrix or Grains M3

P-wave velocity, km/s

4.5

Pore-Fill M4

4.0

M1

M3

3.5

M2

3.0

M4

2.5 2.0

Matrix and Inclusions M5

Fracture-Fill

1.5

M6

M5 0

10

20

30

40

50

60

Gas hydrate saturation, %

70

80

90

100

3.0

M1

2.5

S-wave velocity, km/s

M3

> Microstructural models of hydrate-bearing sediments. In the first five of the six models, gas hydrates (blue) are evenly distributed throughout the sedimentary grains (tan) to a first approximation. Hydrate may occur as cement at grain contacts (top left), as coating on grains (top right), as a component of the grain matrix (middle left) or as pore-filling material (middle right). The fifth model considers sedimentary grains as inclusions in a hydrate matrix (bottom left). The sixth model (bottom right) depicts hydrates as nodules or fracture-fill in fine-grained, low-permeability sediments. These models are used to simulate the response of hydratebearing sediments to logging and seismic measurements. (Adapted from Dai et al, reference 14.)

2.0

M2

1.5

M4

1.0

M5

0.5 0

0

10

20

30

40

50

60

70

80

90

100

Gas hydrate saturation, %

Predicting gas hydrate saturation from seismic data in the Walker Ridge and Green Canyon areas requires a rock physics model that establishes the relationship between those elastic properties that control the speed of acoustic energy through sediments and gas hydrate saturations; in other settings around the world high hydrate concentrations have been associated with increases in acoustic velocities.14 Several models have been proposed to explain this effect, and all of them indicate that these properties are Oilfield Review highly dependent on the location of hydrate in Spring 10 the sediment (above left). Theoretically, hydrate Hydrates Fig. 6 may occur in sedimentary rocks as cement at ORSPRG10-Hydrate Fig. 6 grain contacts or as coating on grains. It may also act as a component of the grain matrix or may fill pores. These microstructural models all consider the hydrate to be evenly distributed in sediments, and equations have been derived to link gas hydrate concentration to elastic properties. Because gas hydrates have also been encountered in cores as nodules and fracture-fill, these less homogeneous forms of distribution must also be considered, although no quantitative treatment of such distributions has been developed.

22

> Comparison of measured and modeled seismic velocities in hydratebearing sediments. Compressional-wave (P-wave) velocities (top) measured in hydrate-rich layers in a Canadian well (blue triangles) are plotted with velocities calculated using the models described in the previous figure. The measured velocities best fit the velocities from the model treating hydrate as a component of the grain matrix (M3). Shear-wave (S-wave) velocities (bottom) show a similar match. (Adapted from Dai et al, reference 14.)

A comparison of seismic velocities computed from these models with those measured in hydrate-bearing rocks indicates that the model in which hydrate acts as a component of the grain matrix fits the data best (above right). In this model hydrate neither coats nor cements sediment grains. Inputs include rock porosity and hydrate saturation, enabling estimates of hydrate saturation if porosity and seismic velocity are known. Furthermore, porosity can be related to seismic velocity, so hydrate saturation can be calculated from velocity alone. Velocities are usually obtained by inversion of seismic data for acoustic impedance, which is the product of density and velocity. However, in gas hydrates density does not vary much with saturation and therefore can be neglected for a first approximation. This makes it possible to estimate saturation solely from acoustic impedance.

14. Shelander D, Dai J and Bunge G: “Predicting Saturation of Gas Hydrates Using Pre-Stack Seismic Data, Gulf of Mexico,” Marine Geophysical Researches, 2010 (in press). Dai J, Xu H, Snyder F and Dutta N: “Detection and Estimation of Gas Hydrates Using Rock Physics and Seismic Inversion: Examples from the Northern Deepwater Gulf of Mexico,” The Leading Edge 23, no. 1 (January 2004): 60–66. Kleinberg RL, Flaum C, Griffin DD, Brewer PG, Malby GE, Peltzer ET and Yesinowski JP: “Deep Sea NMR: Methane Hydrate Growth Habit in Porous Media and Its Relationship to Hydraulic Permeability, Deposit Accumulation, and Submarine Slope Stability,” Journal of Geophysical Research 108, no. B10 (2003): 2508–2525. 15. For a description of the type of inversion used: Mallick S, Oilfield HuangReview X, Lauve J and Ahmad R: “Hybrid Seismic Spring 10 A Reconnaissance Tool for Deepwater Inversion: Exploration,” Hydrates Fig. The 7 Leading Edge 19, no. 11 (November 2000): 1230–1237. ORSPRG10-Hydrate Fig. 7 For more on seismic inversion in general: Barclay F, Bruun A, Rasmussen KB, Camara Alfaro J, Cooke A, Cooke D, Salter D, Godfrey R, Lowden D, McHugo S, Ozdemir H, Pickering S, Gonzalez Pineda F, Herwanger J, Volterrani S, Murineddu A, Rasmussen A and Roberts R: “Seismic Inversion: Reading Between the Lines,” Oilfield Review 20, no. 1 (Spring 2008): 42–63. 16. Boswell et al, reference 13.

Oilfield Review

In support of the JIP effort, geophysicists at WesternGeco performed high-resolution, fullwaveform prestack inversion and combined the results with conventional linear prestack inversion to produce estimates of P-wave and S-wave impedances in the 3D volumes created by the seismic surveys.15 These impedances, in turn, were converted into saturation cubes (right). Predrill gas hydrate saturation estimates in Walker Ridge and Green Canyon clearly highlighted those areas expected to hold the thickest and most highly saturated reservoirs. In April 2009 the JIP drilled and logged five wells at the Walker Ridge and Green Canyon sites. Four of the wells encountered sand reservoirs with gas hydrate at saturations exceeding 50% and potentially as high as 85%.16 At the Green Canyon site one well penetrated nearly 100 ft [30 m] of gas hydrate–bearing sand (below).

8 Depth, ft below rig floor

Horizon B

Well H

BGHS

N

0

Density

Ultrasonic Caliper

Gamma Ray

in.

gAPI

12 0

1.4

ohm.m

40

g/cm3

Hydrate Saturation n = 1.5 2.2

0

Density Used

Ring 100 1

Hydrate saturation, %

> Gas hydrate saturations in Walker Ridge estimated from seismic inversion. Saturations range from 0% to 40% (green to red). Horizon A (left) lies stratigraphically above Horizon B (right). Well H penetrates both horizons within the gas hydrate–stability zone, but Well G penetrates only Horizon A in the gas hydrate–stability zone, intersecting Horizon B at a deeper point. The white dot is an oil and gas industry well not related to the gas hydrate study. The base of the gas hydrate–stability zone is marked by BGHS. (Adapted from Shelander et al, reference 14.)

Poor Density Resistivity

Well H

BGHS

Caliper 12

Well G

Well G

Best Caliper in.

8

Horizon A

100 1.4

3

g/cm

%

100

n = 2.5 2.2

0

%

100

1,340

1,360

1,380

1,400

1,420

Oilfield Review Spring 10 Hydrates Fig. 9 ORSPRG10-Hydrate Fig. 9

1,440

1,460

1,480

> Well logs (left) from a Green Canyon gas hydrate well. High resistivities (Track 3) are the clearest indications of gas hydrates (pink shading) in this 100-ft sand. Deeper, thinner sands also contain hydrates. The caliper log (Track 1) shows washouts in the hydrate-free zones (blue shading). Washouts can lead to poor density results (Track 4). Estimated gas hydrate saturations (Track 5) range from 50% to more than 85% and depend on the saturation exponent, n, used in Archie’s law, which relates resistivity to porosity and saturation. Personnel prepare LWD tools on the Q4000 floating drilling unit (right). (Photograph courtesy of the JIP Leg II Science Team.)

Spring 2010

23

Well H 3,360

Hor

NE

izo

nA

SW

8,600

3,380 3,400

Two-way time, ms

3,440

Ho

rizo

3,460

nB

9,000

3,480

Depth, ft

8,800

3,420

Gamma ray Resistivity Sonic slowness

3,500 3,520

Base

3,540

hydr

ate-s

3,560

9,200

tabil

Hydrate saturation, % 40

ity zo

ne

3,580 3,600

0

9,400 9,380

9,370

9,360

9,350

9,340

9,330

9,320

9,310

9,300

Inline number

> Estimated saturations and acquired well logs through a gas hydrate zone. Seismic inversion predicted high saturations of gas hydrate (reds) in Horizon B at the location of Well H. High concentrations of gas hydrate can be inferred from the high resistivity values (yellow log) and sonic slownesses (green log). The decrease in gamma ray readings (blue log) indicates the layer is a sand. (Adapted from Shelander et al, reference 14.)

Pump Rate, galUS/min

Bit Total Flow Area, in.2 0.52 3.65

0.56 3.13

0.60 2.72

0.65 2.36

0.69 2.06

0.74 1.80

0.79

420 410

3.40

2.92

2.53

2.19

1.92

1.68

1.48

400

3.16

2.71

2.35

2.04

1.78

1.56

1.38

390

2.93

2.51

2.18

1.89

1.65

1.44

1.28

380

2.71

2.32

2.01

1.74

1.53

1.34

1.18

370

2.50

2.14

1.86

1.61

1.41

1.23

1.09

360

2.30

1.97

1.71

1.48

1.30

1.14

1.00

350

2.12

1.81

1.57

1.36

1.19

1.04

0.92

340

1.94

1.66

1.44

1.25

1.09

0.96

0.84

330

1.77

1.52

1.32

1.14

1.00

0.88

0.77

320

1.62

0.80

0.70

310

1.47

0.73

0.64

300

1.33

0.66

0.58

290

1.20

0.91 1.04 1.20 1.39 Oilfield Review Spring 0.83 0.95 1.26 101.09 Hydrates Fig. 11 0.86 0.75 0.99 1.14 ORSPRG10-Hydrate Fig. 110.68 0.78 0.89 1.03

0.59

0.52

280

1.08

0.93

0.81

0.70

0.61

0.53

0.47

270

0.97

0.83

0.72

0.63

0.55

0.48

0.42

1.59

> Optimizing circulation rates and bit design for the Green Canyon area. This table shows bit hydraulic horsepower per square inch (HSI) as a function of the bit total flow area and the circulation, or pump, rate. The light-yellow shading denotes the range of circulation rates and bit sizes that maintains the bit HSI between 1 and 1.5 to minimize hole erosion and optimize the mechanical action of the bit. An additional design criterion governing the circulation rate was to ensure that gas hydrate did not dissociate during drilling.

24

Scientists confirmed that at the Walker Ridge site, gas hydrate occurred in multiple reservoir sands and fully saturated them over their geologic extent. The Gulf of Mexico JIP Legs I and II are the first drilling projects to have prepared predrill estimates of gas hydrate saturation and then tested them by subsequent drilling. The excellent results provide increased confidence in the geologic and geophysical concepts and technologies applied by the JIP team (left).17 Assessing gas hydrate drilling hazards— Drilling wells into gas hydrate accumulations requires consideration of several wellborestability issues. The drilling process must avoid stress-induced mechanical failure, washouts and fluid influx resulting from hydrate dissociation and shallow-water or free-gas flows. In support of the JIP 2009 expedition, Schlumberger geomechanics experts evaluated the proposed drilling locations and flagged sites where excess pore pressure presented potential drilling hazards. They also developed methods to predict the mechanical and phase stability of boreholes drilled in sediments containing gas hydrates. These methods involved calibration correlations relating the mechanical properties of hydrate-bearing sediments to log- and seismicderived data.18 Using numerical simulators, the JIP team modeled the while-drilling borehole temperatures and estimated the energy of impact of drilling fluid streams impinging on the formation from bit nozzles. These analyses enabled the JIP team to evaluate the potential for mechanical failure of the borehole, gas hydrate dissociation and hydraulic erosion of the sediment. Design criteria were developed to optimize bit selection and circulation practice (left). 17. Jones E: “Characterizing Natural Gas Hydrates in the Deep Water Gulf of Mexico: Applications for Safe Exploration and Production Activities, SemiAnnual Progress Report #41330417,” prepared for the US Department of Energy, October 2009, http:// www.netl.doe.gov/technologies/oil-gas/publications/ Hydrates/2009Reports/NT41330_SemiAnnSep2009.PDF (accessed February 10, 2010). 18. Birchwood R, Singh R and Mese A: “Estimating the In Situ Mechanical Properties of Sediments Containing Gas Hydrates,” Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, British Columbia, Canada, July 6–10, 2008. 19. Schlumberger provided several LWD services, including sonicVISION sonic logging, EcoScope multifunction logging, TeleScope high-speed telemetry, geoVISION imaging and PeriScope bed boundary mapping.

Oilfield Review

During the 2009 campaign, several LWD tools were run in the JIP boreholes, including an experimental multipole sonic tool to evaluate shear velocities in the unconsolidated hydrate-rich sediments.19 Transmission of LWD data in real time enabled shipboard and onshore specialists to

modeling and correlation methods (below). The success of the drilling campaign confirmed that with proper planning and careful engineering design, gas hydrate formations can be drilled safely.

update predrill models and to diagnose drilling situations. This made it possible to optimize drilling practices over the course of the expedition. The predictions made by wellbore-stability and downhole temperature models were consistent with observed data, raising confidence in the

Shear Failure Mud Weight 8

lbm/galUS

18

Modeled Pore Pressure 8

lbm/galUS

18

Modeled Horizontal Stress 8

. Elastoplastic wellbore-stability model in Green Canyon Block 955, Well H. High resistivities (Track 1, orange) indicate the presence of gas hydrates. Track 2 shows the friction (green) and dilation (purple) angles. A binary lithology model predicts much higher friction angles in sands than in clays, particularly in shallower sections where the confining stress at the borehole wall is low. The dilation angle is estimated in sands using a correlation; it is assumed to be zero in clays. Track 3 displays the static Young’s modulus (red) and the unconfined compressive strength (blue). Both show a tendency to increase whenever gas hydrate is present in the main target sands, between 8,077 and 8,186 ft, but are relatively unaffected by the presence of gas hydrates in clays. Track 4 contains the output of the wellbore-stability model: pore pressure (blue), shear failure envelope (green), horizontal stress (magenta) and overburden stress (red). The mud weight used to drill the well is shown in brown. The model predicts a stable borehole everywhere except in the olive-shaded intervals, where the shear failure envelope exceeds the mud weight. Such intervals are prone to hole enlargement due to shear failure. Track 5 shows the difference (blue shading) between the bit size (black) and the density caliper (purple). The borehole is generally close to gauge; however, some hole enlargement can be seen in sandy zones between 8,000 and 8,328 ft, where there is little or no gas hydrate. The wellbore-stability model predicts that such zones are too weak to support a borehole. The model also correctly accounts for the strengthening effect of gas hydrates in sand intervals where the borehole is in gauge.

Gamma Ray

Depth, ft

0

Dilation Angle 150 –10

gAPI

0

ohm.m

deg

50 0

Friction Angle

Resistivity 20 –10

deg

Unconfined Compressive Strength MPa

10 8

Static Young’s Modulus 50 0

MPa

500 8

lbm/galUS

18

Out of Gauge

Modeled Shear Failure Envelope lbm/galUS

Bit Size

18 8

in.

12

Modeled Overburden

Density Caliper

lbm/galUS

in.

18 8

12

7,000

7,500

Gas hydrates in clayrich layers

Predicted hole enlargement 8,000

Target gas hydrate – bearing sands

Observed hole enlargement

8,500

Spring 2010


25

Gamagori

0

km

0

a S e

50 mi

50

n pa J a

o f

Na

FI

gh

CI

ou

PA

Tr ai nk

East

China

Sea

C

OC

EA

N

J A P A N

0 0

km

200 mi

200

> The region of the Nankai Trough, offshore Japan. Drilling locations in the eastern Nankai Trough area are shown as red dots (inset). Seismic BSRs (purple) indicate the presence of hydrates over vast areas.

Hydrates in the Eastern Nankai Trough Another area of gas hydrate exploration is offshore Japan, in the region of the eastern Nankai Trough. Seismic data indicate widespread existence of BSRs (left). In 1999 a Japanese government–funded project drilling in the eastern Nankai Trough successfully penetrated a BSR and recovered a number of gas hydrate samples.20 A few years later, in 2001, the Japanese government initiated an 18-year exploration project to evaluate the distribution of gas hydrates, estimate reserves and develop a methane hydrate field.21 As part of this program, 2D and 3D seismic surveys were acquired and 32 wells were drilled through the BSR in water depths of 722 to 2,033 m [2,370 to 6,670 ft]. The base of the hydratestability zone ranges from 177 to 345 m [581 to 1,132 ft] below the seafloor. Of the wells drilled, 16 were logged with LWD tools, 12 were cored, 2 were logged with wireline tools, and 1 was equipped with long-term temperature sensors.22 Cores were retrieved from a variety of hydraterich sediments (below). One of the many studies focused on analysis of well logs for determination of gas hydrate saturation.23 As solids in the pore space, gas hydrates are invisible to NMR tools. Although there are hydrogen atoms in both the water and the methane, they are locked in the hydrate lattice structure and their spins cannot be manipulated by the NMR tool. Their absence from the NMR measurement results in a porosity value that is typically lower than that measured by other tools.

Oilfield Review Spring 10 Hydrates Fig. 14 ORSPRG10-Hydrate Fig. 14 > Gas hydrates from the eastern Nankai Trough. At one site the gas hydrate (white) occupies a layer within a mud-silt zone (left). At a different site, the gas hydrate is disseminated in the pore space of a sand layer (right). The scale is in centimeters.

26

Oilfield Review

Hunting Hydrates in India Gas hydrate is also a potential source of energy for India, which currently does not produce enough oil and gas to fuel its growing economy. The presence of gas hydrates on India’s continental margins has been inferred from BSRs seen in seismic data. The total estimated resource from natural gas hydrates in the country is placed at 1,894 trillion m3 [66,880 Tcf].28 In 1997 the government of India formed the National Gas Hydrates Program (NGHP) to explore and develop the country’s gas hydrate resources.

20. Matsumoto R, Takedomi Y and Wasada H: “Exploration of Marine Gas Hydrates in Nankai Trough, Offshore Central Japan,” presented at the AAPG Annual Convention, Denver, June 3–6, 2001. 21. Fukuhara M, Sugiyama H, Igarashi J, Fujii K, Shun’etsu O, Tertychnyi V, Shandrygin A, Pimenov V, Shako V, Matsubayashi O and Ochiai K: “Model-Based Temperature Measurement System Development for Marine Methane Hydrate-Bearing Sediments,” Proceedings of the 5th International Conference on Gas Hydrates, Trondheim, Norway, June 13–16, 2005. 22. Takahashi H and Tsuji Y: “Multi-Well Exploration Program in 2004 for Natural Hydrate in the NankaiTrough Offshore Japan,” paper OTC 17162, presented at the Offshore Technology Conference, Houston, May 2–5, 2005.

Spring 2010

Porosity Difference Density Porosity

Washout

80

10

in.

Caliper 10

in.

Gamma Ray 0

gAPI

%

0

NMR Porosity

Bit Size Depth, m

This difference can be used to estimate hydrate volume. The method is analogous to the DMR density–magnetic resonance technique developed to determine gas saturation in gas reservoirs.24 Such a technique helped log analysts estimate saturation from wireline logs in an eastern Nankai Trough well.25 Gamma ray, caliper, resistivity, neutron, density, magnetic resonance and sonic measurements showed alternation of hydrate- and non-hydrate-bearing layers (right). The difference between porosities seen by the magnetic resonance tool and those computed from the density tool data corresponds to the approximate volume of hydrate contained in the sediments. Saturations calculated from the resistivity and magnetic resonance responses are comparable except where washouts have affected the density and magnetic resonance readings. Washouts occur mainly in the non-hydratebearing layers. Using all available core, log and seismic data, experts estimate the total amount of methane gas in the surveyed area of the eastern Nankai Trough to be 40 Tcf [1.1 trillion m3].26 The Japanese program has recently announced that it will proceed with preparations to conduct field tests of gas hydrate productivity at sites within the Nankai Trough.27

20

80

Deep Resistivity 20 0.2

ohm.m ohm.m

200 80

%

DMR Porosity %

DMR Water Saturation

0

Neutron Porosity

200 80

Shallow Resistivity 100 0.2

%

100 0

%

0

Resistivity Water Saturation

0 100

%

0

X10

X20

X30

X40

> Formation evaluation in a hydrate zone. Track 1 plots gamma ray (green) and caliper (solid black). Blue fill indicates washed-out intervals. Track 2 contains shallow and deep resistivity data. High resistivities correspond to hydrate-rich zones. Low resistivities signify laminations without hydrate— layers that tend to wash out during drilling. Track 3 contains neutron porosity (dotted blue), density porosity (red), NMR porosity (black) and the DMR porosity obtained by combining density and NMR measurements (green). Gold shading represents the volume of gas hydrate. Track 4 shows the water saturations calculated using the resistivity (red) and densityNMR-difference technique (blue). Several spikes in Tracks 3 and 4 correlate with borehole washouts.

23. Murray D, Kleinberg R, Sinha B, Fukuhara M, Osawa O, 26. Fujii T, Saeki T, Kobayashi T, Inamori T, Hayashi M, Oilfield Endo T and Namikawa T: “Formation Evaluation of GasReview Takano O, Takayama T, Kawasaki T, Nagakubo S, Spring Hydrate Reservoirs,” Transactions of the SPWLA 46th10 Nakamizu M and Yokoi K: “Resource Assessment of Annual Logging Symposium, New Orleans, June 26–29, Fig. 16 Methane Hydrate in the Eastern Nankai Trough, Japan,” Hydrates 2005, paper SSS. paperFig. OTC16 19310, presented at the Offshore Technology ORSPRG10-Hydrate Conference, Houston, May 5–8, 2008. 24. Freedman R, Cao Minh C, Gubelin G, Freeman JJ, McGinness T, Terry B and Rawlence D: “Combining NMR 27. Masuda Y, Yamamoto K, Tadaaki S, Ebinuma T and and Density Logs for Petrophysical Analysis in GasNagakubo S: “Japan’s Methane Hydrate R&D Program Bearing Formations,” Transactions of the SPWLA 39th Progresses to Phase 2,” Fire in the Ice (Fall 2009): 1–6, Annual Logging Symposium, Keystone, Colorado, USA, http://www.netl.doe.gov/technologies/oil-gas/ May 26–29, 1998, paper II. publications/Hydrates/Newsletter/MHNewsFall09. pdf#Page=1 (accessed March 9, 2010). 25. Murray DR, Kleinberg RL, Sinha BK, Fukuhara M, Osawa O, Endo T and Namikawa T: “Saturation, Acoustic 28. Government of India, Directorate General of Properties, Growth Habit, and State of Stress of a Gas Hydrocarbons: “Gas Hydrate: R&D Advances in India,” Hydrate Reservoir from Well Logs,” Petrophysics 47, http://www.dghindia.org/NonConventionalEnergy. no. 2 (April 2006): 129–137. aspx?tab=2#3 (accessed February 17, 2010).

27

BANGLADESH

I

N

D

I

BURMA

A

Mahanadi

Mumbai

Krishna-Godavari Kerala Konkan

Chennai Andaman Islands

0 0

500

km mi

16A

500

7A-D

15A 5A-E14A 11A 6A 4A 2A-B 3A-C 10A-D 12A 13A 20A

KrishnaGodavari

> Exploration sites (red circles) of the 2006 expedition of the Indian National Gas Hydrates Program (NGHP). A scientific team aboard the JOIDES Resolution drilling vessel assessed data from 39 boreholes in four different regions. Samples from the Krishna-Godavari region (inset) contained significant hydrate accumulations. (Adapted from Collett et al, reference 29.)

The first NGHP expedition, in 2006, explored four lenses and wispy subvertical veins oriented in areas of the Indian Ocean (above). The primary a primary direction, with some crossing in a goal of NGHP Expedition 01 was to conduct scien- secondary direction. In the intervals where hydrates reside in pore tific ocean drilling, coring, logging and analytical space, the Archie relationship can be used to activities to assess the geologic Oilfield occurrence, Review determine saturation. However, in other zones, regional context and characteristics ofSpring gas hydrate 10 for example, where hydrate occupies fractures in deposits along the continental marginsHydrates of India.29Fig. 17 Fig. 17 sediments, the method is not The expedition team consisted ofORSPRG10-Hydrate more than low-permeability 100 scientists and professionals representing more applicable, but resistivity logs and images can than 30 universities, national institutes and com- still be used to identify hydrate-filled fractures. Images from an RAB resistivity-at-the-bit LWD panies. During the 113-day operation, the scientific ocean drilling vessel JOIDES Resolution tool clearly show resistive hydrate-filled fractures drilled 39 boreholes in water depths ranging as well as conductive fractures in several holes in from 907 to 2,674 m [2,975 to 8,774 ft]. Scientists the Krishna-Godavari region.30 Fractures in most of recovered 2,850 m [9,350 ft] of core, logged the holes analyzed have steep dips—70° to 80° 12 holes with LWD tools and an additional 13 holes (next page). Stress orientations calculated from with wireline tools, and performed six borehole dip data indicate a maximum horizontal stress seismic surveys. direction perpendicular to the edge of India’s The cores indicate that hydrates occur in a Continental Slope—a finding that is inconsistent variety of settings. In the Indian Ocean, as in with those from other passive continental margins other parts of the world, hydrates are present documented for boreholes deeper than the holes in coarse-grained sediments. More surprising in the NGHP study. This contradiction suggests was the amount of hydrates discovered in fine- that the fractures may be related to local slumps grained sediments, where they occur as layers, and slides, signifying shallow stresses at work rather than deep tectonic stresses.31

28

The shale-dominated interval of hydratefilled fractures encountered at Site NGHP-01-10 is one of the richest marine gas hydrate accumulations ever discovered.32 Among the highlights of the expedition was the discovery of one of the deepest gas hydrate accumulations known: At Site NGHP-01-17, offshore the Andaman Islands, gas hydrate–bearing volcanic ash layers were encountered as far as 600 m [1,970 ft] below the seafloor. Future plans call for a pilot project to produce methane from some of these locations. Other Exploration Efforts The successes of marine hydrate exploration campaigns in Japan and India have encouraged groups in other countries to pursue similar programs. For example, investigative projects in China have begun in areas conducive to hydrate stability. China’s first gas hydrate drilling expedition, GMGS-1, was conducted in 2007 by the Guangzhou Marine Geological Survey (GMGS), China Geological Survey (CGS) and the Ministry of Land and Resources of the People’s Republic of China. The Bavenit geotechnical and scientific drilling vessel visited eight sites in the Shenhu area of the South China Sea. On this expedition, the project team described both a new gas hydrate province and a potentially new mode of hydrate distribution within sediments.33 At each site a pilot hole was drilled and then logged with a suite of high-resolution slimhole wireline tools. From these logs decisions were made either to immediately drill an adjacent coring hole or to move on to another site. At three of the five sites cored, gas hydrates were detected in clay- and silt-rich sediments directly above the base of the hydrate-stability zone. Thickness of the hydrate-rich layers ranged from 10 to 25 m [33 to 82 ft]. Hydrate was distributed evenly in 20% to 40% of the pore volume throughout these fine-grained sediments. While it is common to find hydrate dispersed in coarsegrained sediment and hydrate-filled fractures in clay-dominated sediments, seldom have hydrates been seen disseminated in extremely finegrained layers at such elevated saturations. Further analysis of samples and data collected during the expedition will continue at the GMGS and at laboratories throughout China. Potential future expeditions to the Shenhu area and other regions of the South China Sea margin are under discussion.

Oilfield Review

Deep Resistivity

Caliper

Medium Resistivity

8 in. 20

Depth, m

Producing Methane from Hydrates Although many countries and organizations are finding gas hydrates plentiful and widespread, the problem remains as to how to produce methane from them safely, efficiently and economically. In addressing this problem, a top priority is to understand the dissociation mechanisms of hydrates in different habitats. Safety is also an important issue. Hydrates in pore space strengthen the grain matrix, but when the solid hydrate turns into gas and water, the volume of the pore-filling material can increase significantly; the sediment becomes fluidized, compromising the strength and stiffness of the sediment column. This can lead to compaction of the sediment in the producing zone and over burden, destabilization of faults, sand production and other processes that may potentially damage infrastructure. Techniques for hydrate exploitation will have to succeed without causing sediment instability. To recover methane from hydrates, experts concur that exploiting hydrates in sandy sediments has the highest probability of success and requires the lowest investment in new technology. Two principal techniques have been field tested for recovering methane from hydrates: heating and depressurization. For ease of access, tests have been conducted on hydrate accumulations on land, in permafrost regions. Comprehensive tests have taken place at the Mallik gas hydrate field in the Canadian Northwest Territories and at the Mount Elbert prospect in Alaska.

Gamma Ray

Density

Deep Resistivity Image Statically Enhanced

Shallow Resistivity Resistive

gAPI g/cm3 60 120 1.3 2.0 0.2

ohm.m

200

E

Deep Resistivity Image Dynamically Enhanced

Conductive Resistive S

W

E

Conductive S

W

Dip and Dip Direction Gas Hydrate– Filled Fracture Dip, deg 50 60 70 80

65

70

75

> Borehole image and core from the Krishna-Godavari region. Among the logs acquired in Well NGHP-01-10A, a borehole image log (Tracks 4 and 5) exhibits high-resistivity gas hydrate (light colors) in steeply dipping fractures (Track 6). Dips are consistently 70° to 80°. (Log courtesy of Ann Cook, Lamont-Doherty Earth Observatory.) The core (inset) shows gas hydrate (white) filling a fracture in black fine-grained sediments. (Photograph courtesy of the NGHP Expedition 01.)

29. US Geological Survey, “Results of the Indian National Gas Hydrate Program (NGHP) Expedition 01,” http://energy.usgs.gov/other/gashydrates/india.html (accessed February 17, 2010). Collett TS, Riedel M, Cochran J, Boswell R, Kumar P, Sathe A and NGHP Expedition 01 Scientific Party: “Geologic Controls on the Occurrence of Gas Hydrates in the Indian Continental Margin: Results of the Indian National Gas Hydrate Program (NGHP)

Spring 2010

Expedition 01,” adapted from an oral presentation at 31. Cook and Goldberg, reference 30. the AAPG Annual Convention, San Antonio, Texas, Oilfield Review32. Collett et al, reference 29. April 20–23, 2008, http://www.searchanddiscovery. 33. Zhang H, Yang S, Wu N, Su X, Holland M, Schultheiss P, Spring 10 net/documents/2008/08135collett/ndx_collett01.pdf K, Butler H, Humphrey G and GMGS-1 Science (accessed February 17, 2010). Hydrates Fig. 18 Rose Team: “Successful and Surprising Results for China’s 30. Cook A and Goldberg D: “Stress and Gas Hydrate-Filled ORSPRG10-Hydrate 18 Drilling Expedition,” Fire in the Ice First Fig. Gas Hydrate Fracture Distribution, Krishna-Godavari Basin, India,” (Fall 2007): 6–9, http://www.netl.doe.gov/technologies/ Proceedings of the 6th International Conference on Gas oil-gas/publications/Hydrates/Newsletter/ Hydrates, Vancouver, British Columbia, Canada, July HMNewsFall07.pdf (accessed February 17, 2010). 6–10, 2008.

29

o r t B e a u f a S e

Mallik e zi

n ke ac Bay M

Ice

Yukon Territory Northwest Territories

d roa Inuvik 0 0

km 50 mi

50

> The Mallik field, Northwest Territories, Canada. The Mallik field has been the site of hydrate discoveries and research since 1972. The site is accessible only in winter by way of an ice road. (Photograph courtesy of Scott Dallimore, Geological Survey of Canada.)


> A Mallik gas hydrate core sample collected in 2002. Gas hydrate (white) resides within the pore space of a pebbly conglomerate. (Photograph courtesy of Scott Dallimore, Geological Survey of Canada.)

30

Mallik Gas Hydrate Production The Mallik field, located on the Mackenzie Delta in the Beaufort Sea, has a long history of gas hydrate investigation (left).34 Hydrates were discovered in 1972 during exploration drilling by Imperial Oil Ltd. In the early 1990s the Geological Survey of Canada (GSC) undertook a regional appraisal of gas hydrates in the Mackenzie Delta area. Later, in 1998, the Japan National Oil Corporation (JNOC) and the GSC, working with several other institutions, completed the Mallik 2L-38 Gas Hydrate Research Well Program. Results from these studies establish the Mallik field as one of the most concentrated gas hydrate accumulations in the world.35 Interbedded sequences of hydrate-rich sands occur at depths from 890 to 1,106 m [2,920 to 3,629 ft], with some layers surpassing 30 m [100 ft] in thickness.36 In certain zones hydrate saturations exceed 80% (below left). The abundance of subsurface data available, the advantage of access by land and the similarities with many offshore hydrate deposits make the Mallik site attractive for research. In 2002 a new program was initiated to conduct production testing of hydrates from the Mallik field.37 The production research program included the GSC and JNOC, as well as formal collaboration with the International Continental Scientific Drilling Program and institutions from the USA, Germany and India. A 1,166-m [3,825-ft] production well was drilled, cored, logged and cased, and two 1,188-m [3,898-ft] observation wells were drilled and cased. The response of the formation to thermal stimulation and depressurization was monitored using fiber-optic distributed temperature sensors (DTS) installed in each well, repeat cased hole logging in the production well and cross-well seismic surveys conducted in the monitoring wells. The 13-m [43-ft] interval selected for the thermal test was a relatively clean sandstone bounded by shales and located below the permafrost, with hydrate saturation ranging from 70% to 85%.38 Heated brine was circulated past open perforations. The fluid and produced gas returned to surface in the annulus between the circulation string and the casing. During the 5-day test cumulative gas production was 516 m3 [18.2 Mcf].39 The differences noted in pretest openhole resistivity logs and post-test cased hole resistivity logs were used to determine the radius of hydrate dissociation over the test interval (next page).40 The analysis indicated that the dissociation radius was not uniform and was greatest near the outlet of the circulation string, where fiber-optic DTS sensors had recorded the highest temperatures. In addition to variations in temperature across

Oilfield Review

34. Dallimore SR, Collett TS, Uchida T, Weber M, Chandra A, Mroz TH, Caddel EM, Inoue T, Takahashi H, Taylor AE and Mallik Gas Hydrate Research Team: “The Mallik Gas Hydrate Field: Lessons Learned from 30 Years of Gas Hydrate Investigation,” AAPG Bulletin 88, no. 13 (supplement), 2004. 35. Dallimore et al, reference 34. 36. Dallimore SR, Uchida T and Collett TS (eds): Scientific Results from JAPEX/JNOC/GSC Mallik 2L-38 Gas Hydrate Research Well, Mackenzie Delta, Northwest Territories, Canada: Geological Survey of Canada Bulletin 544, 1999. 37. Dallimore SR and Collett TS (eds): Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada: Geological Survey of Canada Bulletin 585, 2005, available at http://geoscan.ess.nrcan.gc.ca/cgi-bin/ starfinder/0?path=geoscan.fl&id=fastlink&pass= &search=R%3D220702&format=FLFULL (accessed April 1, 2010).

Spring 2010

Resistivity, ohm.m 900

1

10

100

Radius, m 1,000

–2

–1

0

1

2

910

Collar Depth, m

the zone, variations in porosity and permeability and in water invasion may have affected heat exchange with the formation. Deeper in the test well, small-scale pressuredrawdown tests were also carried out over six hydrate-rich zones using a modified MDT modular formation dynamics tester.41 The tool collected samples of gas and water and measured changes in pressure and flow rates. After analysis of these and other data, along with intensive numerical modeling efforts, the research team concluded that depressurization would be a more effective method than thermal stimulation for inducing hydrate dissociation. The next phase of production testing research at Mallik was undertaken in the winters of 2007 and 2008. For this project Japan was represented by the Japan Oil, Gas and Metals National Corporation (JOGMEC), and Canada was represented by Natural Resources Canada. Aurora Research Institute in Inuvik, Northwest Territories, acted as the operator. This program was designed to advance long-term production testing using a depressurization technique. Considerable emphasis was also placed on design and testing of various geophysical monitoring techniques and evaluation of downhole completion technologies for gas hydrate production. Operations during the first winter—the site is accessible only when the 200-km [124-mi] ice road from Inuvik is frozen—involved installing well infrastructure and conducting a short production test in the Mallik 2L-38 well drilled as part of the 1998 research program. The test zone was a 12-m [39-ft] interval near the bottom of a hydrate-rich zone. An ESP was set below the perforations to depressurize the formation by lowering the water level in the well. Because of permit restrictions during the first year, the operation plans called for disposal of produced water in the same wellbore. To accomplish this, gas-water

920

Collar 930

CHFR log CHFR model

Openhole resistivity log Resistivity model

Hole radius Dissociation radius

> Determining hydrate dissociation volume. Logs were acquired before and after a 2002 thermal stimulation production test in the Mallik field (left). Openhole resistivity logs acquired before the test (orange) were compared with CHFR cased hole formation resistivity logs run afterward (purple) to determine the radius of hydrate dissociation over the test interval. The differences correspond to a modeled radius of dissociation (right) that varies with depth. (Adapted from Anderson et al, reference 38.)

separation was performed in the wellbore; the in the 5 days of thermal stimulation in the 2002 gas was produced to surface and the produced test.44 Sand production was much greater than water was reinjected into water zones below the anticipated, a problem that would have to be gas hydrate test interval.42 overcome in future operations. The team planned The April 2007 production test was performed to return the next year, when freezing conditions without sand control measures to monitor and would allow operations to continue. After reviewing the experience from the first measure the direct formation response to pressure drawdown.43 As expected, a significant winter’s operation, the team returned to Mallik in amount of sand was produced—so much that the the winter of 2008 with a simplified research proOilfield Review gram. This time produced water was flowed to test was curtailed after 60 hours. However, Springduring 10 the surface and reinjected into a water-disposal the most successful 12.5 hours ofHydrates pumping, Fig. 21 a custom-designed sand screen 830 m3 [29.3 Mcf] of gas was produced, more than well. In ORSPRG10-Hydrate Fig.addition, 21

“The Mallik 2002 Consortium: Drilling and Testing a Gas Hydrate Well,” National Methane Hydrates R&D Program, US Department of Energy, http://www. netl.doe.gov/technologies/oil-gas/FutureSupply/ MethaneHydrates/projects/DOEProjects/Mallik-41007. html (accessed February 11, 2010). 38. Anderson BI, Collett TS, Lewis RE and Dubourg I: “Using Open Hole and Cased-Hole Resistivity Logs to Monitor Gas Hydrate Dissociation During a Thermal Test in the Mallik 5L-38 Research Well, Mackenzie Delta, Canada,” Petrophysics 49, no. 3 (June 2008): 285–294. 39. Dallimore and Collett, reference 37. 40. Anderson et al, reference 38. 41. Hancock SH, Dallimore SR, Collett TS, Carle D, Weatherill B, Satoh T and Inoue T: “Overview of Pressure-Drawdown Production-Test Results for the JAPEX/JNOC/GSC et al. Mallik 5L-38 Gas Hydrate Production Research Well,” in Dallimore SR and Collett TS (eds): Scientific Results from the Mallik

2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada: Geological Survey of Canada Bulletin 585, 2005, available at http://geoscan.ess.nrcan.gc.ca/cgi-bin/ starfinder/0?path=geoscan.fl&id=fastlink&pass= &search=R%3D220702&format=FLFULL (accessed April 1, 2010). 42. Yamamoto K and Dallimore S: “Aurora-JOGMECNRCan Mallik 2006-2008 Gas Hydrate Research Project Progress,” Fire in the Ice (Summer 2008): 1–5, http:// www.netl.doe.gov/technologies/oil-gas/publications/ Hydrates/Newsletter/HMNewsSummer08.pdf#Page=1 (accessed February 17, 2010). 43. “Energy from Gas Hydrates: Assessing the Opportunities & Challenges for Canada,” Report in Focus (July 2008), http://www.scienceadvice.ca/documents/(2008_07_07)_ GH_Report_in_Focus.pdf (accessed January 27, 2010). 44. Hancock et al, reference 41.

31

assembly was installed before testing to limit sand influx into the wellbore (left). The 6-day test was highly successful, with sustained gas flows ranging from 2,000 to 4,000 m3/d [70 to 140 Mcf/d].45 Operations continued smoothly at three target drawdown pressures. The Mallik tests successfully demonstrated a field-scale proof-of-concept for gas production from hydrates by depressurization using conventional oilfield technologies adapted for arctic conditions.

Water

Gas

Permafrost zone

650

Depth, m

ESP Gas separator Heater

890

Pressure and temperature sensors

1,070

Sand screen 1,100

Bridge plug Aquifers

> Well completion for the Mallik 2008 depressurization production test. An electric submersible pump (ESP) installed above the perforations depressurized the formation by lowering the water level in the well. Sand screens prevented sand influx from the unconsolidated formation into the borehole. Hydrate dissociation produced gas and water. After gas-water separation, gas flowed to the surface, and produced water was sampled then reinjected in a separate water-disposal well. (Adapted from Yamamoto and Dallimore, reference 42.)

Flowing bottomhole pressure Flowing bottomhole temperature (FBHT) Hydrate-stability pressure at initial FBHT

4 3

10

2

8

End flow period 2

6

1

End flow period 3

0

4 2 0

End flow period 1 0

1

2


3

4

5

6

7

–1

8

9

10

11

Flowing bottomhole temperature, °C

Flowing bottomhole pressure, MPa

12

–2

Test time, h

> Gas hydrate production test. An MDT tool was used to reduce well pressure by drawing water from a layer containing high saturations of gas hydrate. Between fluid-withdrawal, or flow, periods, the pump was shut off, pressure build-up was monitored and gas and water samples were collected. During the first flow period the bottomhole pressure (blue) was kept above the hydrate-stability pressure (green), so no methane was produced. During the second and third flow periods the bottomhole pressure was decreased to below the stability pressure, allowing the gas hydrate to dissociate and gas to be produced. (Adapted from Anderson et al, reference 51.)

32

Gas Hydrate Production in Alaska The USGS has studied gas hydrate accumulations in the Alaska North Slope and currently estimates they contain between 25.2 and 157.8 Tcf [714 and 4,468 billion m3] of undiscovered technically recoverable natural gas.46 Much of this resource occurs within gas hydrate deposits near existing oil and gas production facilities (next page).47 Early work on hydrates in this area dates to 1972, when ARCO and Exxon drilled, cored and tested methane hydrates in the Northwest Eileen State-2 well.48 However, that testing indicated subcommercial production rates; as a result, Alaska’s gas hydrate zones were not considered 45. Report in Focus, reference 43. 46. “Assessment of Gas Hydrate Resources on the North Slope, Alaska, 2008,” U.S. Geological Survey, Fact Sheet 2008-3073 (October 2008), http://pubs.usgs. gov/fs/2008/3073/pdf/FS08-3073_508.pdf (accessed January 18, 2010). 47. “Alaska North Slope Gas Hydrate Reservoir Characterization,” National Methane Hydrates R&D Program, US Department of Energy, http://www. netl.doe.gov/technologies/oil-gas/futuresupply/ methanehydrates/projects/DOEProjects/Alaska-41332. html (accessed January 18, 2010). 48. Collett TS: “Natural Gas Hydrates of the Prudhoe Bay and Kuparuk River Area, North Slope, Alaska,” AAPG Bulletin 77, no. 5 (May 1993): 793–812. 49. “BP Drills Alaska North Slope Gas Hydrate Test Well to Assess Potential Energy Resource,” BP press release (February 2007), http://www.bp.com/genericarticle. do?categoryId=2012968&contentId=7028944 (accessed January 18, 2010). 50. Boswell R, Hunter R, Collett T, Digert S, Hancock S, Weeks M and Mount Elbert Science Team: “Investigation of Gas Hydrate-Bearing Sandstone Reservoirs at the “Mount Elbert” Stratigraphic Test Well, Milne Point, Alaska,” Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, British Columbia, Canada, July 6–10, 2008. 51. Anderson BJ, Wilder JW, Kurihara M, White MD, Moridis GJ, Wilson SJ, Pooladi-Darvish M, Masuda Y, Collett TS, Hunter RB, Narita H, Rose K and Boswell R: “Analysis of Modular Dynamic Formation Test Results from the Mount Elbert-01 Stratigraphic Test Well, Milne Point Unit, North Slope of Alaska,” Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, British Columbia, Canada, July 6–10, 2008. 52. Collett T and Boswell R: “The Identification of Sites for Extended-Term Gas Hydrate Reservoir Testing on the Alaska North Slope,” Fire in the Ice (Summer 2009): 12–16, http://www.netl.doe.gov/technologies/oil-gas/ publications/Hydrates/Newsletter/MHNewsSummer09. pdf (accessed January 27, 2010). 53. US DOE, reference 47. 54. Report in Focus, reference 43.

Oilfield Review

as potential gas reservoirs but were treated as drilling hazards to be dealt with as deeper targets were developed. The recent assessment of Alaska gas hydrates as a resource began in 2001 with a cooperative research program between BP Exploration Alaska Inc., the US Department of Energy and the USGS. BP provided a 3D seismic survey over its Milne Point production unit. Through analysis of the 3D seismic data, public well logs and reservoir modeling studies, USGS scientists identified several potential accumulations. The highest ranked prospect was selected for acquisition of well log and core data. In 2007 the project team drilled and collected data from the Mount Elbert gas hydrate research well.49 Hydrate-bearing formations were encountered 1,800 to 2,500 ft [550 to 760 m] below the surface. As a precaution against hydrate dissociation and hole destabilization, oil-base drilling fluid was chilled to below 32°F [0°C]. The resulting borehole remained in gauge, enabling highquality data collection. Data include LWD and extensive wireline openhole logs, more than 500 ft [152 m] of continuous core, and MDT pressure tests. Log analysis confirmed the presence of 100 ft of hydratesaturated sand in which porosities reach 40%, intrinsic permeabilities are in the multiple-Darcy range and hydrate saturations vary between 45% and 75%.50 Nuclear magnetic resonance logs indicate the presence of mobile water even in the most hydrate-saturated intervals. Mobile water, which is removed from the formation to initiate depressurization, appears to be a prerequisite for producing methane from gas hydrate reservoirs that are not otherwise in contact with free gas or water. The MDT tests exhibited a variety of results depending on drawdown pressures.51 During the first flow period the test interval was intentionally held at pressures above the hydrate equilibrium pressure; hydrate dissociation did not occur and no gas was produced (previous page, bottom). In the second and third flow periods the well pressures were below the gas hydrate–stability pressure and gas was produced. The pressure responses were successfully modeled using reservoir simulators. A key observation of the simulation studies is that short-term tests do not necessarily indicate the fully developed flow behavior of a gas hydrate reservoir. The pore space available for fluid flow changes as hydrate dissociates. For example, in

Spring 2010

Alaska USA CANADA

Point Barrow Prudhoe Bay

ARCTIC

OC E AN

Northern Alaska gas hydrate total petroleum system National Petroleum Reserve–Alaska Arctic National Wildlife Refuge 0 0

km

100 mi

Mount Elbert well 100

Kuparuk River oil field

Milne Point 3D seismic survey

Prudhoe Bay oil field

> Gas hydrates in Alaska. The northern Alaska gas hydrate total petroleum system is shaded in blue-gray. The limit of the gas hydrate–stability zone is outlined in red. The area covered by the 3D seismic survey is shown as a red-dashed rectangle. (Modified from USGS Fact Sheet 2008-3073, reference 46).

the Mount Elbert case, when the well pressure Early Days for Hydrates was greater than the hydrate-stability pressure, The current state of understanding of the producin situ effective permeability was 0.12 to 0.17 mD. ibility of gas from hydrates is analogous to that of Decreasing the wellbore pressure to below the coalbed methane and heavy-oil sands about level required for hydrate stability caused disso- 30 years ago.54 Although recovery from both coalciation of hydrate within the pore space, and the bed methane formations and oil sands took seveffective permeability increased. eral decades to become commercially viable, it is To conduct extended production tests in the too early to determine the development horizon Alaska North Slope, scientists will need year- of gas hydrate resources. round access to a wellsite with existing infraOilfield Review As far as resource supply and access are con10 cerned, several countries are optimistic about the structure. Seven potential surface Spring locations 23 within the Prudhoe Bay, Kuparuk RiverHydrates and MilneFig. potential of gas hydrates to meet future energy ORSPRG10-Hydrate Fig. 23 Point fields have been evaluated.52 A site in the needs. Japan, India, China and South Korea, all Prudhoe Bay field has been identified as optimal countries that import oil and gas, have launched because of its combination of low geologic risk, programs to explore the possibilities of unlocking low operational risk, maximal operational flexi- methane from the hydrate cage. As with other bility and promise of meaningful reservoir unconventional resources, development of hydrate response. BP and the other companies with work- reserves will undoubtedly benefit from technoloing interest in the site are discussing plans for gies originally designed for conventional oil and gas exploration and production. —LS long-term production testing there.53

33