Seismic data and gravity cores indicate that natural gas hydrate deposits are present in the Columbus Basin off the East Coast of Trinidad. These data led to the initiation of a research program aimed at delineating and characterizing this unconventional resource. Already the areal extents of deposits in two offshore blocks have been estimated. In this study, the theoretical thickness of the hydrate stability zone for one of the blocks was estimated and additional reservoir properties collated from globally located hydrate-bearing strata. These data were used to conduct a parametric study on the potential volume of natural gas in the block.

Quantification of this unconventional gas resource is important since natural gas is a premium fuel and its use is likely to increase in the short and medium term. Factors contributing to this phenomenon are (i) the increasing global energy demand, (ii) natural gas is environmentally friendlier than oil and coal in terms of total emissions, and (iii) oil and coal, which are high carbon fuels, and greater contributors to global warming. In addition, international interest stems from the fact that gas hydrate deposits are affected by temperature and pressure, and release of methane from these deposits can occur if there are certain changes to these conditions. This could impact oceanic and atmospheric chemistry, and in due course climate.

The data collated from the globally located hydrate-bearing strata indicated that porosities were generally greater than 16%, and hydrate saturations were as high as 80%. These data along with the theoretical thickness of the gas hydrate stability zone indicated that the potential volume of natural gas in situ may be greater than 1 TCF.

This finding is significant since if the technical challenges associated with producing this unconventional resource are overcome, the natural gas stored in this hydrate deposit represents a potential additional source of gas which can be used to help meet Trinidad and Tobago‟s future energy needs.

Trinidad and Tobago‟s economy is based, for the most part, on the oil and gas industry, with emphasis now being placed on the exploration of the deep water acreage in the Columbus Basin off the east coast of Trinidad. In this area, where water depths exceed 500 m, near seafloor pressures and temperatures favour the formation of natural gas hydrates. Already sea floor gravity cores indicate the presence of hydrates between Trinidad and Barbados, and seismic events which have been interpreted to be bottom simulating reflectors (BSR), associated with the presence of gas hydrates, have been observed (Brooks et al., 2004; Figueira et al., 2010).

The continuous growth in global energy consumption (BP, 2010) suggest that it would be prudent to investigate the occurrence of these deposits as this unconventional natural gas resource presents an opportunity for strengthening the local economy. A research program aimed at delineating and characterizing this unconventional resource was thus initiated, and the areal extent of hydrate-bearing sediments in two offshore blocks were determined (Ramdatt et al, 2007; Figueira et al. 2010). In this study, the theoretical thickness of the hydrate stability zone for one of the blocks, i.e. Block 27, was estimated. Additional reservoir properties were collated from globally located hydrate-bearing sediments and used to conduct a parametric study on the potential volume of gas stored in the hydrate-bearing sediments in the block.

Hydrates are crystalline solids formed from water and smaller molecules, and are part of the group of compounds known as clathrates (Carrol, 2009). These compounds are structured such that molecules of one or more substances are enclosed in a structure built from molecules of another substance. The conditions necessary for hydrate formation include low temperatures and high pressures, as well as the presence of sufficient amounts of the each of the molecules. Natural gas hydrates are composed of water and natural gas, with the gas molecules trapped in cavities composed of water molecules (Sloan and Koh, 2008).

Natural gas hydrate-bearing sediments are found in polar and oceanic regions, in a relatively narrow zone which is generally parallel to the terrestrial or seabed surface (Dillon and Max, 2003). The thickness of this zone is determined by sea floor temperature, geothermal gradient, pore pressure, pore water salinity, and the gas composition (Taylor and Kwan, 2004). In Trinidad, interest lies in oceanic hydrate-bearing sediments.

Figure 1 illustrates the temperature-depth/pressure relationship for oceanic hydrate-bearing sediments. Natural gas hydrates will exist if water and gas are available in sufficient quantities, and if reservoir pressure and temperature lie to the left of the methane-hydrate phase boundary curve. As also indicated, sea water temperature decreases with water depth down to the seafloor, below which the temperature increases as a result of the geothermal gradient. Gas hydrates can occur beyond the seafloor, to a depth which has a maximum temperature of approximately 20°C. This zone constitutes the gas hydrate stability zone (GHSZ). Figure 1 also illustrates that once the depth to the sea floor, water temperature, and the geothermal gradient are known, the theoretical maximum thickness of the GHSZ can be estimated.

Figure 1

Schematic of Depth/Pressure-Temperature Relationship for Oceanic Hydrate-Bearing Sediment.

Figure 1

Schematic of Depth/Pressure-Temperature Relationship for Oceanic Hydrate-Bearing Sediment.

Close modal

For gas to be produced from hydrate reservoirs, the gas must first be extracted from the hydrates via dissociation or "melting" of the gas hydrates. It is this factor that makes the production of natural gas from hydrates "unconventional." Two of the recommended methods of hydrate dissociation for gas production from these reservoirs are thus depressurization and thermal stimulation. Two other methods involve injection of chemical inhibitors and CO2.

The applicability of these production techniques is dependent on the type or „class‟ of deposits (Moridis et al., 2009). Class I deposits, which are the easiest to destabilize, are composed of two layers: the hydrate-bearing layer (HBL) and an underlying two-phase fluid zone containing mobile gas and liquid water. Class II deposits comprise of two zones: a HBL overlying a zone of mobile water, while Class III deposits are composed of a single HBL with no underlying mobile fluids. Class IV pertains specifically to oceanic accumulations which are dispersed, of low hydrate saturation (i.e. <10%), and lack confining geologic strata.

Depressurization involves lowering the pressure in the hydrate stability zone to below the hydrate stability pressure. As the hydrates dissociate, trapped gas is released and flows to the wellbore. Thermal stimulation involves raising the temperature of the hydrate-bearing sediments above the hydration temperature by injection of steam or hot water. Max (2006) noted that the highest flow rates appear to be achieved by the combination of depressurization and heating techniques. Moridis et al. (2009) was in agreement with this view and stated that thermal stimulation can be effectively used in conjunction with depressurization for the production from Class II hydrate deposits, and for more localized applications such as the destruction of secondary hydrate and ice. It was also concluded that as a process by itself, thermal stimulation is slow, inefficient and more costly than simple depressurization.

The use of chemical inhibitors involves the introduction of substances such as electrolytes, salts or alcohols which would cause a shift in the pressure-temperature (P–T) equilibrium such as the lowering of the hydrate formation temperature. Calcium chloride (CaCl2) and methanol (CH3OH) have been found to be the most effective inhibitors. Both serve to restructure water molecules around the ions (or the alcohol) and cause clustering of water around the organic molecule to be more difficult. While the use of gas hydrate inhibitors has been shown to be technically feasible, the large volume of chemical required makes the technique costly and not environmentally friendly.

More recently, consideration has been given to the replacement of methane with carbon dioxide (CO2) in the hydrates (Cha, 2010). The stability condition of CO2 hydrate is known to be more favorable than that of CH4 hydrate and thus, the exchanging of CH4 with CO2 is considered to be a favorable approach toward long-term storage of CO2 and recovery of CH4 gas. The advantage of this method is that the process is also an environmentally friendly one.

Block 27 lies in the Columbus Basin, a rich depositional centre which extends from Venezuela to southeast Trinidad. Sediments previously deposited by the South American Orinoco River created a prolific hydrocarbon province with several conventional oil and gas reservoirs. These sands are one hundred to several hundred feet in thickness with high porosities (20-30%) and permeabilities (10-1000 md) (Jemmott, 2005). Given that the east coast is a prolific hydrocarbon province, the probability is also high that the hydrocarbon gas needed for the formation of hydrate deposits is present and in sufficient quantities.

In a previous study, three-dimensional (3D) seismic data for the Block 27 were evaluated for the presence of natural gas hydrate indicators (Figueira et al., 2010). The dataset covered an area of approximately 1789 km2 of transition zone between the continental shelf and slope in the Columbus Basin. Analysis of the data showed the presence of a bottom simulating reflector (BSR). This occurs as a result of the response of seismic signals to the change in acoustic impedance between sediments which contain hydrates, and underlying sediments which may contain water and/or free gas in its pore spaces. The location of the BSR is pressure-temperature dependent, and delineates the base of what is often called the gas hydrate stability zone (GHSZ). It is thus not a sediment interface, but cuts across strata and generally parallels the seafloor.

In the Block 27 area, the BSR was observed to parallel the seafloor for the most part, and cut across strata. The areal extent of the BSR was determined to be 517 km2 or approximately 29% of the Block 27 area.

For the Block 27 area, while 3D seismic data were available with which to delineate the BSR and hence the areal extent of potential hydrate-bearing sediments, limited additional data were available with which to further characterize these sediments. As such, to make an initial attempt at estimating possible volumes of natural gas trapped in the hydrate-bearing sediments, the conventional petroleum method was used. To facilitate this approach, the following data were required; areal extent of hydrate-bearing sediments, the thickness of the hydrate-bearing zone, average porosity of the hydrate layer, and hydrate saturation.

In the Block 27 area, the bottom simulating reflector (BSR) was mapped over an areal extent of 516.8 km2 or approximately 29% of the study area. Due to the dispersed characteristic of hydrate zones, and as assumed in previous studies (Parlaktuna and Ergogmus 2001), it was assumed that good quality reservoir rock with high hydrate saturation would be present in 10% of the mapped area.

Sea floor depths ranged from 900 m to 1300 m with associated sea floor temperatures of 6 to 7°C. Local geothermal gradients also vary from 15°C/km to 33°C/km (0.8°F/100 ft to 1.8°F/100 ft) (Rodrigues, 1989). These data were used to provide estimates of the depths to the base of the GHSZ. Estimates of the thickness of the GHSZ were then calculated by finding the difference between the seafloor depth and the depth to the base of the GHSZ. In addition, since the thickness of the hydrate-bearing reservoir is generally less than the thickness of the hydrate stability zone, the literature was surveyed for the sand thicknesses of other hydrate-bearing reservoirs (along with reservoir porosities and hydrate saturations). Table 1 which summarizes these data indicates that while the sand thicknesses were at times > 100 m, they were generally < 50 m. Sand thickness values of 10, 20, 30 and 50m were thus used in the calculations.

Table 1

Published Data for Gas Hydrate-bearing Sediments

LocationAccumulationHydrate Sand Thickness (m)Gas Hydrate Concentration (%)Porosity (%)Recovery Factor (%)Reference
Alaska, North Slope Milne Point 30 (2 sands) 65 35-40  Collett et al., 2011  
Alaska, North Slope Prudhoe Bay Unit - L Pad 68 (4 sands) 60-75 40 36 (Alaska Eileen Trend) Collett et al., 2011; Moridis et al., 2008
Alaska, North Slope Kuparuk 12.5 65 40  Collett et al., 2011  
Canada Mallik, Mackenzie Delta >110 (ten layers) up to 80 25-40  Moridis et al., 2008; Bellefleur et al., 2006  
China, South Sea Shenhu 10-43 20-40 38  Zhang et al., 2010  
Gulf of Mexico Walker Ridge  40%   Birchwood et al., 2010  
Gulf of Mexico Green Canyon 30 50->85%   Birchwood et al., 2010  
Gulf of Mexico Alaminos Canyon 18 60-80 30  Moridis et al., 2008
Japan Eastern Nankai Trough 75 m   30 Birchwood et al., 2010; Matsuzawa et al., 2006; Masuda et al., 2010
Russia Messoyakha 50 20 16-38  Grover et al., 2008
LocationAccumulationHydrate Sand Thickness (m)Gas Hydrate Concentration (%)Porosity (%)Recovery Factor (%)Reference
Alaska, North Slope Milne Point 30 (2 sands) 65 35-40  Collett et al., 2011  
Alaska, North Slope Prudhoe Bay Unit - L Pad 68 (4 sands) 60-75 40 36 (Alaska Eileen Trend) Collett et al., 2011; Moridis et al., 2008
Alaska, North Slope Kuparuk 12.5 65 40  Collett et al., 2011  
Canada Mallik, Mackenzie Delta >110 (ten layers) up to 80 25-40  Moridis et al., 2008; Bellefleur et al., 2006  
China, South Sea Shenhu 10-43 20-40 38  Zhang et al., 2010  
Gulf of Mexico Walker Ridge  40%   Birchwood et al., 2010  
Gulf of Mexico Green Canyon 30 50->85%   Birchwood et al., 2010  
Gulf of Mexico Alaminos Canyon 18 60-80 30  Moridis et al., 2008
Japan Eastern Nankai Trough 75 m   30 Birchwood et al., 2010; Matsuzawa et al., 2006; Masuda et al., 2010
Russia Messoyakha 50 20 16-38  Grover et al., 2008

The conventional reservoirs located off the east coast of Trinidad exhibit high porosities of 20 to 30% (Lumsden et al., 2002; Jemmott, 2005). An examination of the data in Table 1 indicated that while the porosity of hydrate-bearing reservoirs ranged from 5-85%, it was generally greater than 20%. The typical porosity values for the east coast of 20 to 30% were thus selected for use. Hydrate saturations of 20, 40, 60 and 80% were also selected for use in the computations based on the data collated and summarized in Table 1. It was also assumed that 1 volume of hydrate would yield 164 volumes of natural gas at standard conditions (SC) of temperature and pressure.

The potential volumes of gas initially in place at standard conditions of pressure and temperature were calculated using Eqn. 1, and the potential recoverable reserves were estimated by applying a recovery factor of 30%. This factor was selected based on numerical simulation studies of depressurization-induced gas production from oceanic methane hydrate (Masuda et al., 2010).

Hydrate volume = Areal extent of reservoir * sand thickness * porosity * hydrate saturation * 164 Eqn. 1

The depth to the base of the GHSZ as a function of sea floor depth and geothermal gradient are summarized in Table 2, and presented graphically in Figure 2. These data indicate that for a given sea water depth, as the geothermal gradient increased, the depth to the base of the GHSZ decreased. Also for a given geothermal gradient, the depth to the base of the GHSZ increased with water depth. The data indicated that for the range of water depths and geothermal gradients considered, the depth to the base of the GHSZ ranged from approximately 1040 to 2140 m.

Table 2

Effect of Sea Floor Depth and Geothermal Gradient on Depth to Base of Hydrate Stability Zone.

Sea FloorGeothermal Gradient (°C/km)
Depth (m) 15 18 22 25 29 33 
Sea FloorGeothermal Gradient (°C/km)
Depth (m) 15 18 22 25 29 33 
Depth to base of Gas Hydrate Stability Zone (m)
900 1405 1245 1155 1110 1065 1040 
1000 1620 1430 1335 1260 1220 1185 
1100 1810 1610 1490 1420 1360 1330 
1200 1985 1770 1645 1555 1500 1460 
1300 2140 1930 1790 1705 1645 1600 
Depth to base of Gas Hydrate Stability Zone (m)
900 1405 1245 1155 1110 1065 1040 
1000 1620 1430 1335 1260 1220 1185 
1100 1810 1610 1490 1420 1360 1330 
1200 1985 1770 1645 1555 1500 1460 
1300 2140 1930 1790 1705 1645 1600 
Figure 2

Depth of Base of the GHSZ as a Function of Seawater Depth and Geothermal Gradient

Figure 2

Depth of Base of the GHSZ as a Function of Seawater Depth and Geothermal Gradient

Close modal

The thickness of the GHSZ as a function of sea water depth and geothermal gradient are summarized in Table 3 and presented graphically in Figure 3. These data indicate that for a given sea water depth, as the geothermal gradient increased, the thickness of the GHSZ decreased. Also for a given geothermal gradient, the thickness of the GHSZ increased with water depth. The data indicated that for the range of water depth and geothermal gradients considered, the thickness of the GHSZ ranged from approximately 140 to 840 m.

Table 3

Effect of Sea Floor Depth and Geothermal Gradient on Thickness of the Gas Hydrate Stability Zone.

Sea FloorGeothermal Gradient (°C/km)
Depth (m) 15 18 22 25 29 33 
Sea FloorGeothermal Gradient (°C/km)
Depth (m) 15 18 22 25 29 33 
Thickness of Gas Hydrate Stability Zone (m)
900 505 345 255 210 165 140 
1000 620 430 335 260 220 185 
1100 710 510 390 320 260 230 
1200 785 570 445 355 300 260 
1300 840 630 490 405 345 300 
Thickness of Gas Hydrate Stability Zone (m)
900 505 345 255 210 165 140 
1000 620 430 335 260 220 185 
1100 710 510 390 320 260 230 
1200 785 570 445 355 300 260 
1300 840 630 490 405 345 300 
Figure 3

Thickness of GHSZ as a Function of Geothermal Gradient and Seawater Depth.

Figure 3

Thickness of GHSZ as a Function of Geothermal Gradient and Seawater Depth.

Close modal

As indicated previously, the thickness of the hydrate-bearing reservoir is generally less than the thickness of the hydrate stability zone. Data collated on reservoir thicknesses, and summarized in Table 1, indicates that the thicknesses were generally less than 50 m. This thickness is within the range of thicknesses of the hydrate stability zone computed for the Block 27 area and the thicknesses of the conventional reservoirs off the east coast. Sand thicknesses of 10, 20, 30 and 50 m were thus used in the computations.

Gas Volumes and Recoverable Reserves

Using the range of data collected, gas volumes and recoverable reserves were estimated. These results are summarized in Table 4 and presented graphically in Figures 4-7. Figure 4 indicates that, assuming the areal extent or the reservoir extends over 10 percent of the mapped area, and the porosity of the hydrate-bearing layer is 20%, the potential gas volume could range from 0.003*1012 to 0.068*1012 m3 (0.12 to 2.4 TCF) as the reservoir thickness increases from 10 to 50m. Figure 5 indicates that assuming the porosity of the hydrate-bearing layer is 30%, the potential gas volume in the hydrate-bearing strata could range from 0.005*1012 to 0.102*1012 m3 (0.18 to 3.6 TCF).

Table 4

Estimates of Gas initially in Place and Potential Recoverable Reserves

A (km2)% Mapped Area UsedPor (%)Sh (%)h (m)PV (109 m3)Hydrate yield (m3@ SC / m3)GIIP (1012m3 @ SC)GIIP (TCF)RF (%)Potential Reserves (1012 m3 @ SC)Potential Reserves (TCF)
517 10% 20% 20% 10 0.02 164 0.0034 0.12 30% 0.0010 0.04 
517 10% 20% 40% 10 0.04 164 0.0068 0.24 30% 0.0020 0.07 
517 10% 20% 60% 10 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 20% 80% 10 0.08 164 0.0136 0.48 30% 0.0041 0.14 
517 10% 20% 20% 20 0.04 164 0.0068 0.24 30% 0.0020 0.07 
517 10% 20% 40% 20 0.08 164 0.0136 0.48 30% 0.0041 0.14 
517 10% 20% 60% 20 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 20% 80% 20 0.17 164 0.0271 0.96 30% 0.0081 0.29 
517 10% 20% 20% 30 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 20% 40% 30 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 20% 60% 30 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 20% 80% 30 0.25 164 0.0407 1.44 30% 0.0122 0.43 
517 10% 20% 20% 50 0.10 164 0.0170 0.60 30% 0.0051 0.18 
517 10% 20% 40% 50 0.21 164 0.0339 1.20 30% 0.0102 0.36 
517 10% 20% 60% 50 0.31 164 0.0509 1.80 30% 0.0153 0.54 
517 10% 20% 80% 50 0.41 164 0.0678 2.40 30% 0.0203 0.72 
517 10% 30% 20% 10 0.03 164 0.0051 0.18 30% 0.0015 0.05 
517 10% 30% 40% 10 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 30% 60% 10 0.09 164 0.0153 0.54 30% 0.0046 0.16 
517 10% 30% 80% 10 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 30% 20% 20 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 30% 40% 20 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 30% 60% 20 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 30% 80% 20 0.25 164 0.0407 1.44 30% 0.0122 0.43 
517 10% 30% 20% 30 0.09 164 0.0153 0.54 30% 0.0046 0.16 
517 10% 30% 40% 30 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 30% 60% 30 0.28 164 0.0458 1.62 30% 0.0137 0.49 
517 10% 30% 80% 30 0.37 164 0.0610 2.16 30% 0.0183 0.65 
517 10% 30% 20% 50 0.16 164 0.0254 0.90 30% 0.0076 0.27 
517 10% 30% 40% 50 0.31 164 0.0509 1.80 30% 0.0153 0.54 
517 10% 30% 60% 50 0.47 164 0.0763 2.70 30% 0.0229 0.81 
517 10% 30% 80% 50 0.62 164 0.1017 3.59 30% 0.0305 1.08 
A (km2)% Mapped Area UsedPor (%)Sh (%)h (m)PV (109 m3)Hydrate yield (m3@ SC / m3)GIIP (1012m3 @ SC)GIIP (TCF)RF (%)Potential Reserves (1012 m3 @ SC)Potential Reserves (TCF)
517 10% 20% 20% 10 0.02 164 0.0034 0.12 30% 0.0010 0.04 
517 10% 20% 40% 10 0.04 164 0.0068 0.24 30% 0.0020 0.07 
517 10% 20% 60% 10 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 20% 80% 10 0.08 164 0.0136 0.48 30% 0.0041 0.14 
517 10% 20% 20% 20 0.04 164 0.0068 0.24 30% 0.0020 0.07 
517 10% 20% 40% 20 0.08 164 0.0136 0.48 30% 0.0041 0.14 
517 10% 20% 60% 20 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 20% 80% 20 0.17 164 0.0271 0.96 30% 0.0081 0.29 
517 10% 20% 20% 30 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 20% 40% 30 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 20% 60% 30 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 20% 80% 30 0.25 164 0.0407 1.44 30% 0.0122 0.43 
517 10% 20% 20% 50 0.10 164 0.0170 0.60 30% 0.0051 0.18 
517 10% 20% 40% 50 0.21 164 0.0339 1.20 30% 0.0102 0.36 
517 10% 20% 60% 50 0.31 164 0.0509 1.80 30% 0.0153 0.54 
517 10% 20% 80% 50 0.41 164 0.0678 2.40 30% 0.0203 0.72 
517 10% 30% 20% 10 0.03 164 0.0051 0.18 30% 0.0015 0.05 
517 10% 30% 40% 10 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 30% 60% 10 0.09 164 0.0153 0.54 30% 0.0046 0.16 
517 10% 30% 80% 10 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 30% 20% 20 0.06 164 0.0102 0.36 30% 0.0031 0.11 
517 10% 30% 40% 20 0.12 164 0.0203 0.72 30% 0.0061 0.22 
517 10% 30% 60% 20 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 30% 80% 20 0.25 164 0.0407 1.44 30% 0.0122 0.43 
517 10% 30% 20% 30 0.09 164 0.0153 0.54 30% 0.0046 0.16 
517 10% 30% 40% 30 0.19 164 0.0305 1.08 30% 0.0092 0.32 
517 10% 30% 60% 30 0.28 164 0.0458 1.62 30% 0.0137 0.49 
517 10% 30% 80% 30 0.37 164 0.0610 2.16 30% 0.0183 0.65 
517 10% 30% 20% 50 0.16 164 0.0254 0.90 30% 0.0076 0.27 
517 10% 30% 40% 50 0.31 164 0.0509 1.80 30% 0.0153 0.54 
517 10% 30% 60% 50 0.47 164 0.0763 2.70 30% 0.0229 0.81 
517 10% 30% 80% 50 0.62 164 0.1017 3.59 30% 0.0305 1.08 

A - Area of mapped BSR

h - Net sand thickness

Sh - Hydrate saturation

GIIP - Potential gas initially in place

RF - Recovery factor

Por - Porosity

PV - Hydrate pore volume

Figure 4

Potential Gas Initially in Place (Porosity = 20%)

Figure 4

Potential Gas Initially in Place (Porosity = 20%)

Close modal
Figure 5

Potential Gas Initially in Place (Porosity = 30%)

Figure 5

Potential Gas Initially in Place (Porosity = 30%)

Close modal
Figure 6

Potential Gas Reserves (Porosity = 20%)

Figure 6

Potential Gas Reserves (Porosity = 20%)

Close modal
Figure 7

Potential Gas Reserves (Porosity = 30%)

Figure 7

Potential Gas Reserves (Porosity = 30%)

Close modal

Figure 6 indicates that assuming the areal extent or the reservoir extends over 10 percent of the mapped area, the porosity of the hydrate-bearing layer is 20%, and the recovery factor is 30%, possible gas reserves could range from 0.001*1012 to 0.02*1012 m3 (0.04 to 0.72 TCF) as the reservoir thickness increases from 10 to 50m. Figure 7 indicates that assuming the porosity of the hydrate-bearing layer is 30%, possible gas reserves could range from from 0.0015*1012 to 0.03*1012 m3 (0.05 to 1.1 TCF).

Data selection for the estimation of the potential volumes of gas in place in the Block 27 area was guided by published data from other hydrate-bearing reservoirs and the properties of the conventional reservoirs off the east coast of Trinidad. Notwithstanding the fact that conservative assumptions were made, given the range of possible volumes of gas initially in place, this study emphasizes the need to obtain data specific to the Block 27 area and by extension the east coast.

While exploration wells have been drilled off the east coast, and in the Block 27 area, the interval immediately beneath the sea floor was generally not logged or cored. As such much valuable well log and core data are not available to assist with the characterization of potential hydrate-bearing zones. To increase the specificity and accuracy of the results, caliper, spontaneous potential, gamma ray, resistivity, neutron porosity and sonic velocity logs can be used to better define gas hydrate zones and to estimate gas quantity (Goodman et al., 1982). It is recommended that future wells drilled in this area be logged and cored over the shallow intervals.

In addition, gas composition significantly impacts the conditions under which gas hydrates are stable, and hence the theoretical depth to the base of the GHSZ and the thickness of the interval. For example, in the Gulf of Mexico, at a pressure equivalent of 2500 m, the base of the hydrate stability zone occurs at 21°C when the gas composition is 100% methane (Dillon et al., 2003). At the same pressure, when the gas concentration is 93% methane, 4% ethane and 1% propane with smaller amounts of higher hydrocarbons, the base of the stability zone will occur at 23°C. For a gas concentration of 62% methane, 9% ethane and 23% propane along with some heavier hydrocarbons, the phase limit will be at 28°C. These data indicate that site-specific gas samples should also be taken and analysed to allow for determination of hydrate pressure-temperature relationships for the local reservoirs.

Subsea pressure and temperature data indicate that the oceanic sediments in Block 27 exist at conditions that favour hydrate formation. Block 27 offshore Trinidad also contains a seismic event which has been interpreted to be a BSR associated with the presence of gas hydrates. Using the data collected, potential gas volume ranged from 0.003*1012 to 0.102*1012 m3 (0.12 to 3.6 TCF), and possible recoverable reserves ranged from 0.001*1012 to 0.03*1012 m3 (0.04 to 1.1 TCF). This range of data emphasises the need for additional data such as well log, core, geothermal gradients and gas compositional data, specific to Block 27, for detailed evaluation of the hydrate deposits. Future wells drilled in this area should be logged and cored over the shallow intervals to provide the much needed data to assist with detailed characterization of the hydrate-bearing sediments.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

The authors are grateful for financial assistance from The Campus Research and Publication Fund of the University of the West Indies, St Augustine.

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