CreateS an Easy Route for Oil to Follow From the Rock to a Well

Depositional model and diagenetic evolution of hydrocarbon reservoirs in deep dolomites of the Ordos Basin, China

Zhongtang Su , ... Shenglin Xu , in The Ordos Basin, 2022

Abstract

Natural gas reservoirs in the intracratonic Ordos Basin have been examined for their sedimentological and geochemical characteristics in order to get a better insight into their depositional conditions and diagenetic evolution. The dolomite reservoir rocks originated in a tidal flat that extended by cyclic progradation on an epeiric platform. The tidal flat successions extended laterally as a progradational wedge in each cycle of sea-level fluctuation. The peritidal shoal facies in the wedge represent potential dolomite reservoirs. They can be recognized by the presence of dolo-arenites that have been altered by diagenesis. Although continuing destructive diagenesis has led to reservoir densification, burial- and facies-dependent dolomitization and dissolution mostly continued in peritidal shoal facies, thus improving the reservoir quality of the dolomites. The findings help targeting deep dolomite gas reservoirs.

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The Road Ahead and Other Thoughts

Sanjeev Rajput , Naresh Kumar Thakur , in Geological Controls for Gas Hydrate Formations and Unconventionals, 2016

10.3.1 Tight Gas Reservoirs

Tight gas refers to natural gas reservoirs produced from reservoir rocks with such low permeability that considerable hydraulic fracturing is required to harvest the well at economic rates. These resources are sealed in extremely impermeable, hard rock, making the underground formation extremely "tight". Tight gas reservoirs are generally defined as having less than 0.1 millidarcy (mD) matrix permeability and less than 10% matrix porosity. Tight gas can also be trapped in sandstone or limestone formations that are atypically impermeable or nonporous, also known as tight sand. Many of the low-permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low-permeability carbonates, shales, and coal seams. For successful production from tight gas reservoirs, a vertical well drilled and completed must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Compared with a conventional gas production scenario, more wells needs to be drilled in tight gas reservoirs to recover the gas-in-place. These reservoirs do not have depth constraints, they can be developed deep or shallow, high or low pressure and temperature, stacked multilayered or single layer and homogeneous, or naturally fractured. According to the department of Energy and Climate Change UK (www.gov.uk), wells produce from low-porosity sandstones and carbonate reservoirs. The gas is sourced outside the reservoir and migrates into the reservoir over geological time. Some tight gas reservoirs have also been found to be sourced by underlying coal and shale source rocks, in the so-called basin centerd gas (BCG) accumulations. A global map of of tight gas resources is shown in Fig. 10.4.

Figure 10.4. Global Map of tight gas potential. (Source: http://pacwestcp.com/education/shaleunconventional-resources/)

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Unconventional Gas Reservoirs

Tarek Ahmed , Paul D. McKinney , in Advanced Reservoir Engineering, 2005

Example 3.18

^a The following production data is reported by Ikoku for a gas well:

Date	Time (years)	qt (MMscf/day)	G p(t) (MMscf)
Jan. 1, 1979	0.0	10.00	0.00
July 1, 1979	0.5	8.40	1.67
Jan. 1, 1980	1.0	7.12	3.08
July 1, 1980	1.5	6.16	4.30
Jan. 1, 1981	2.0	5.36	5.35
July 1, 1981	2.5	4.72	6.27
Jan. 1, 1982	3.0	4.18	7.08
July 1, 1982	3.5	3.72	7.78
Jan. 1, 1983	4.0	3.36	8.44

Estimate the future production performance for the next 16 years.

Solution

Step 1.

Determine the type of decline that adequately represents the historical data. This can be done by constructing the following two plots:

(1)

Plot q_t vs. t on a semilog scale as shown in Figure 3.47. The plot does not yield a straight line and, thus, the decline is not exponential.

Figure 3.47. Rate–time plot for Example 3.18.

(2)

Plot q_t vs. G _p(t) on semilog paper as shown in Figure 3.48. The plot again does not produce a straight line and, therefore, the decline is not a harmonic.

Figure 3.48. Rate—cumulative plot for Example 3.18.

The generated two plots indicate that the decline must be hyperbolic

Step 2.

From Figure 3.47, determine the initial flow rate q _i by extending the smooth curve to intercept with the y axis, i.e., at t = 0, to give:

$q_{\text{i}}=10\text{MMscf}/\text{day}$

Step 3.

Select the coordinates of the other end point on the smooth curve as (t ₂, q ₂), to give:

$\begin{array}{l}{t}_2=4\text{years}\\ q_2=3.36\text{MMscf}/\text{day}\end{array}$

Step 4.

Calculate q ₁ from Equation 3.5.32 and determine the corresponding time:

$q_1=\sqrt{q_{\text{i}}{q}_2}=\sqrt{\left(10\right)\left(3.36\right)}=5.8\text{MMscf}/\text{day}$

The corresponding time t ₁ = 1. 719 years.

Step 5.

Assume b = 0.5, and solve Equation 3.5.33 iteratively for b:

$\begin{array}{l}f\left(b\right)=t_2{\left(\frac{q_{\text{i}}}{q_1}\right)}^b-t_1{\left(\frac{q_{\text{i}}}{q_2}\right)}^b-\left(t_2-t_1\right)\\ f\left(b\right)=4{\left(1.725\right)}^b-1.719{\left(2.976\right)}^b-2.26\end{array}$

and:

$\begin{array}{l}{f}^{\backslash }\left(b^k\right)=t_2{\left(\frac{q_{\text{i}}}{q_1}\right)}^{b^k}ln\left(\frac{q_{\text{i}}}{q_1}\right)-t_1{\left(\frac{q_{\text{i}}}{q_2}\right)}^{b^k}ln\left(\frac{q_{\text{i}}}{{\text{q}}_2}\right)\\ f^{\backslash }\left(b^k\right)=2.18{\left(1.725\right)}^{b}1.875{\left(2.976\right)}^b\end{array}$

with:

$b^{k+1}=b^k-\frac{f\left(b^k\right)}{f^{\backslash }\left(b^k\right)}$

The iterative method can be conveniently performed by constructing the following table:

k	bk	f(b)	f \(b)	bk +1
0	0.500000	7.57 × 10 3	−0.36850	0.520540
1	0.520540	−4.19 × 10-4	−0.40950	0.519517
2	0.519517	−1.05 ×10-6	−0.40746	0.519514
3	0.519514	−6.87 × 10-9	−0.40745	0.519514

The method converges after three iterations with a value of b = 0.5195.

Step 6.

Solve for D _i by using Equation 3.5.36:

$\begin{array}{l}{D}_{\text{i}}=\frac{{\left(q_{\text{i}}/q_2\right)}^b-1}{b{t}_2}\\ =\frac{{\left(10/3.36\right)}^{0.5195}}{\left(0.5195\right)\left(4\right)}=0.3668{\text{yaer}}^{-1}\end{array}$

or on a monthly basis D _i = 0.3668/12 = 0.0306 month⁻¹

or on a daily basis D _i = 0.3668/365 = 0.001 day⁻¹

Step 7.

Use Equations 3.5.19 and 3.5.23 to predict the future production performance of the gas well. Note in Equation 3.5.19 that the denominator contains D_it and, therefore, the product must be dimension-less, or:

$\begin{array}{l}{q}_t=\frac{10\left({10}^6\right)}{{\left[1+0.5195D_{\text{i}}t\right]}^{\left(1/0.5195\right)}}\\ \frac{10\left({10}^6\right)}{{\left[1+0.5195\left(0.3668\right)\left(t\right)\right]}^{\left(1/0.5195\right)}}\end{array}$

where:

q _t = flow rate, MMscf/day

t = time, years

D _i = decline rate, year⁻¹

In Equation 3.5.23, the time basis in q_i is expressed in days and, therefore, D _i must be expressed in day⁻¹, or:

$\begin{array}{l}{G}_{\text{p}\left(t\right)}=\left[\frac{q_{\text{i}}}{D_{\text{i}}\left(1-b\right)}\right]\left[1-{\left(\frac{q_t}{q_{\text{i}}}\right)}^{1-b}\right]\\ =\left[\frac{10\left({10}^6\right)}{\left(0.001\right)\left(1-0.5195\right)}\right]\times \left[1-{\left(\frac{q_t}{\left(10\right)\left({10}^6\right)}\right)}^{1-0.5195}\right]\end{array}$

Results of step 7 are tabulated below and shown graphically in Figure 3.49:

Time (years)	Actual q (MMscf/day)	Calculated q (MMscf/day)	Actual cum. gas (MMMscf)	Calc. cum. gas (MMMscf)
0	10	10	0	0
0.5	8.4	8.392971	1.67	1.671857
1	7.12	7.147962	3.08	3.08535
1.5	6.16	6.163401	4.3	4.296641
2	5.36	5.37108	5.35	5.346644
2.5	4.72	4.723797	6.27	6.265881
3	4.18	4.188031	7.08	7.077596
3.5	3.72	3.739441	7.78	7.799804
4	3.36	3.36	8.44	8.44669
5		2.757413		9.557617
6		2.304959		10.477755
7		1.956406		11.252814
8		1.68208		11.914924
9		1.462215		12.487334
10		1.283229		12.987298
11		1.135536		13.427888
12		1.012209		13.819197
13		0.908144		14.169139
14		0.819508		14.484015
15		0.743381		14.768899
16		0.677503		15.027928
17		0.620105		15.264506
18		0.569783		15.481464
19		0.525414		15.681171
20		0.486091		15.86563

Figure 3.49. Decline curve data for Example 3.18.

Gentry (1972) developed a graphical method for the coefficients b and D _i as shown in Figures 3.50 and 3.51. Arps's decline curve exponent b is expressed in Figure 3.50 in terms of the ratios q _i/q and G _p/(tq _i) with an upper limit for q _i/q at 100. To determine the exponent b, enter the graph with the abscissa with a value of G _p/(tq _i) that corresponds to the last data point on the decline curve and enter the coordinates with the value of the ratio of initial production rate to that of the last rate on the decline curve q_i/q. The exponent b is read by the intersection of these two values. The initial decline rate D _i can be determined from Figure 3.51 by entering the ordinate with the value of q_i/q and moving to the right to the curve that corresponds to the value of b. The initial decline rate D _i can be found by reading the value on the abscissa divided by the time t from q _i to q.

Figure 3.50. Relationship between production rate and cumulative production.

(After Gentry, 1972)

Figure 3.51. Relationship between production rate and time.

(After Gentry, 1972)

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Recovery, storage, and transportation

James G. Speight Ph.D., D.Sc. , in Natural Gas (Second Edition), 2019

5.5.1 Pipelines

After extraction from the reservoir, natural gas must be transported to different places to be processed, stored, and then finally delivered to the end consumer and this can occur by means of a pipeline or ship. Thus once natural gas is extracted from onshore and offshore sites, it is transported to consumers, typically by way of pipelines. Before it reaches the pipelines, however, it needs to be purified into the state it will be in when it enters homes and businesses. This requires the separation of various hydrocarbons and fluids from the pure natural gas to produce "pipeline quality" dry gas. Restrictions are placed on the quality of natural gas that is allowed to enter pipelines. Natural gas can also be stored in large underground areas because demand is higher in different seasons of the year. From the large pipelines, the gas goes into smaller pipelines called mains, and then further into even smaller pipes called services that lead directly into homes and buildings to be heated. Natural gas can also be cooled to a very cold temperature and stored as a liquid. Changing the phase of the natural gas from gas to liquid allows for easier storage because it takes up less space. Then, when it needs to be distributed, it is returned to its original state and sent through pipelines.

There are essentially three major types of pipelines along the natural gas transportation route: (1) the gathering pipeline system, (2) the transmission pipeline system, sometimes referred to as the interstate pipeline system, and (3) the distribution system.

Gathering systems, primarily made up of small-diameter, low-pressure pipelines, move raw natural gas from the wellhead to a natural gas processing plant or to an interconnection with a larger mainline pipeline. Transmission pipelines are typically wide-diameter, high-pressure transmission pipelines that transport natural gas from the producing and processing areas to storage facilities and distribution centers. Compressor stations (or pumping stations) on the pipeline network keep the natural gas flowing forward through the pipeline system. Local distribution companies deliver natural gas to consumers through small-diameter, lower pressure service lines. Whatever the pipeline system, there is the need to determine if the natural gas received at the wellhead has a high sulfur content and a high carbon dioxide content (sour gas), a specialized sour gas gathering pipe must be installed. Sour gas is extremely corrosive and dangerous, thus its transportation from the wellhead to the sweetening plant must be done carefully (Speight, 2014b).

Thus an issue that always arises at the wellhead when natural gas is transported by pipeline is the degree of processing at the wellhead to remove potential corrosive contaminants that would seriously affect the integrity (corrosivity) of the pipeline. While carbon dioxide and hydrogen sulfide are often considered to be noncorrosive in the dry state, the presence of water in the natural gas can render these two gases extremely corrosive (Speight, 2014b). This emphasizes the need for compositional analysis of the natural gas as it exits the production well. As a result of the compositional analysis, the pipeline operators can make the decision about the extent of the wellhead treating such as separation of (1) hydrocarbon gas liquids, (2) nonhydrocarbon gases, and (3) water from the natural gas before the (treated) gas is delivered into a mainline transmission system.

Major transportation pipelines usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline and natural gas must be processed to produce "pipeline quality" dry natural gas. Some field processing can be accomplished at or near the wellhead; however, the complete processing of natural gas takes place at a processing plant, usually located in a natural gas producing region. Thus, from the wellhead, natural gas is transported to processing plants through a network of small-diameter, low-pressure gathering pipelines which may consist of a complex gathering system can consist of thousands of miles of pipes, interconnecting the processing plant to upwards of 100 wells in the area.

Thus it is essential that the composition of the gas be known so that natural-gas processing can begin at the wellhead. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. A natural gas processing plant is a facility designed to clean raw natural gas by separating impurities and various nonmethane hydrocarbons and fluids to produce what is known as pipeline quality dry natural gas. A gas processing plant is also used to recover NGLs (condensate, natural gasoline, and liquefied petroleum gas (LPG)) and sometimes other substances such as sulfur-containing constituents and should be (at least) checked for sulfur content and for residues to ensure that the LPG meets the specification (Speight, 2015, 2018).

Four basic types of LPGs are provided to cover the common use applications, particularly LPGs consisting of propane, propene (propylene), butane, and mixtures of these materials that are intended for use as domestic, commercial and industrial heating, and engine fuels. However, care must be taken to in sampling of the liquefied gases to ensure that the sample is representative otherwise the test results may not be significant (Speight, 2018). All four types of LPGs should conform to the specified requirements for vapor pressure, volatile residue, residue matter, relative density, and corrosion. There is also a further series of standard test methods that can be used to provide information about the composition and properties of domestic and industrial fuel gases (Speight, 2018).

While some of the needed processing can be accomplished at or near the wellhead (field processing), the complete processing of natural gas takes place at a processing plant, usually located in a natural gas producing region. The extracted natural gas is transported to these processing plants through a network of gathering pipelines, which are small-diameter, low-pressure pipes. A complex gathering system can consist of thousands of miles of pipes, interconnecting the processing plant to upwards of 100 wells in the area. In addition to processing done at the wellhead and at centralized processing plants, some final processing is also sometimes accomplished at straddle extraction plants. These plants are located on major pipeline systems. Although the natural gas that arrives at these straddle extraction plants is already of pipeline quality, in certain instances there still exist small quantities of NGLs, which are extracted at the straddle plants.

The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex, but usually involves four main processes to remove the various impurities: (1) oil and condensate removal, (2) water removal, (3) separation of NGLs, and (4) hydrogen sulfide removal, and (5) carbon dioxide removal (Chapter 4: Composition and properties) (Mokhatab et al., 2006; Speight, 2007, 2014a). If mercury is present in the gas, typically as trace amounts, opinions differ whether or not the mercury should be removed at the wellhead. The presence of mercury can cause corrosion of aluminum heat exchangers as well as cause environmental pollution. If needed, there are two forms of removal processes: (1) regenerative processes and (2) nonregenerative processes. The regenerative process uses sulfur-activated carbon or alumina, while nonregenerative processes use silver on a molecular sieve (Mokhatab et al., 2006; Speight, 2007, 2014a).

In addition, hydrogen sulfide and carbon dioxide can be removed by olamine scrubbing (Mokhatab et al., 2006; Speight, 2007, 2014a; Kidnay et al., 2011) and heaters and scrubbers are installed, usually at or near the wellhead. The scrubbers serve primarily to remove sand and other large-particle impurities. The heaters ensure that the temperature of the gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates (NGHs) tend to form when temperatures drop. These hydrates are solid or semisolid compounds, resembling ice-like crystals and when gas hydrates accumulate, they can impede the passage of natural gas through valves and gathering systems. After processing, the pipeline quality natural gas is injected into gas transmission pipelines and transported to the end-users. This often involves transportation of the gas over hundreds of miles, as the location of gas production is generally not the location where the gas is used.

Nevertheless, whatever of the extent of the gas processing operations (at the wellhead or in a processing facility) it is essential that the composition of the gas be known through analysis in order to ensure a (relatively) pure product for transportation and that the gas meets sales specification goals.

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Exploration Examples of Lithological and Stratigraphic Reservoirs

Ming Li , Yimin Zhao , in Geophysical Exploration Technology, 2014

11.3.2 Deep Volcanic Gas Reservoir Exploration Challenges and Technical Solutions

Widely distributed Mesozoic volcanic rocks with good accumulation conditions are the major natural gas reservoirs in Songliao Basin. But since there are only a few outcrops and little core and testing data, it is difficult to research the eruptive stage, cycle, occurrence, lithology, and distribution of the volcanics. The shielding effect of volcanic rocks and deep burial lowers the S–N ratio of deep seismic data. Therefore, it is difficult to predict distribution, exploration targets, reservoir anisotropy, and degree of gas saturation in igneous rocks. These factors affect future exploration and prospect evaluation of natural gas accumulations in Songliao Basin igneous rocks and also raise to a higher standard of accuracy the volcanic reservoir prediction technologies.

Because of the above-mentioned research difficulties, solving the problem of volcanic gas reservoir evaluation requires a step-by-step approach. Because of igneous gas reservoir output characteristics and laws, as well as rock geophysical and logging features grading from simple to difficult, we have reduced the scope of reservoir evaluation from large to small so that we may establish a technical series of volcanic rock reservoir evaluations.

Studies have shown that the volcanic rocks' overall geophysical characteristics are high density, high magnetic susceptibility and resistivity, and high seismic velocity of seismic waves and energy absorption characteristics. Igneous log response characteristics are high density, high resistivity, high natural gamma, low natural potential, and low interval transit time. These characteristics of igneous rocks laid the foundation and conditions for applying geophysical techniques to volcanic rock reservoir prediction.

The identification and prediction of igneous rocks follow these four steps: (1) use gravity and magnetic methods to determine the igneous aerial extent to narrow the exploration target, (2) use the thick layer wave impedance, multiple parameters of lithology inversion, seismic facies, seismic attributes, and energy absorption analysis to forecast the igneous target and lock the exploration targets, (3) use reservoir multiple-parameter inversion, multiple-factor analysis, and tectonic stress analysis to identify and evaluate volcanic reservoirs to find the porous and permeable reservoirs, and (4) detect and delineate the scope of the gas-bearing volcanic rocks through absorption coefficient, pattern recognition, and AVO recognition (Figure 11.39).

FIGURE 11.39. Volcanic rock recognition and evaluation technology flow chart.

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Additional topics

John Carroll , in Natural Gas Hydrates (Fourth Edition), 2020

11.5.2.1 Messoyakha

An interesting example of a hydrate reservoir is the Messoyakha field in Siberia. This is a natural gas reservoir in a cold region of the world. The field was discovered in 1967 and has been exploited commercially with production from this field beginning in 1970. The reservoir had about 850 BCF of natural gas some of which is frozen in the hydrate.

The gas composition is 98.6% methane, 0.1% ethane, 0.1% C₃+, 0.5% carbon dioxide, and 0.7% nitrogen.

The top of the reservoir is at a depth of slightly more than 700   m and the porous formation extends to about 900   m. At approximately 800   m the pressure and temperature intersect the hydrate curve for the gas in this reservoir. Therefore there is a free gas zone on the top of the reservoir and a hydrate layer at the bottom.

Gas can be produced from the free gas zone in the top. As this gas is produced, the pressure in the reservoir falls. The reduction in the pressure melts the hydrate releasing additional gas and thus increasing the pressure.

More details about this field can be found in Tanahashi (1996) and Makogon et al. (2007).

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Transport Fuel – LNG and Methane

Gouthami Senthamaraikkannan , ... Vinay Prasad , in Future Energy (Second Edition), 2014

13.4.1 Thermogenic Natural Gas

Thermogenic natural gas is available as associated gas in crude oil reservoirs and as non-associated gas in natural gas reservoirs and in the form of condensates (also known as wet gas). Unconventional sources such as condensates have been available as shale gas, tight gas and CBM, but were not commercially exploitable at large scales until recently.

The proven natural gas reserves worldwide were reported to be 208.4×10¹²  m³ (tcm) in 2011, increasing from estimates of 196.1×10¹²  m³ (tcm) in 2010 and 168.5×10¹²  m³ (tcm) in 2001, according to one source [7], while other sources [8] estimate a total of 462×10¹²  m³ (tcm) of conventional and 328×10¹²  m³ (tcm) of unconventional reserves to be in existence (though this is yet to be proven). The regional distribution of natural gas reserves is summarised in Table 13.1, and the distribution of conventional and unconventional reserves is summarised in Table 13.2.

Table 13.1. Proven Worldwide Natural Gas Reserves/(10¹²  m³).

Country	Reserves	Country	Reserves
United States	8.5	Bahrain	0.3
Canada	2.0	Iran	33.1
Mexico	0.4	Iraq	3.6
Total North America	10.8	Kuwait	1.8
Argentina	0.3	Oman	0.9
Bolivia	0.3	Qatar	25.0
Brazil	0.5	Saudi Arabia	8.2
Colombia	0.2	Syria	0.3
Peru	0.4	United Arab Emirates	6.1
Trinidad and Tobago	0.4	Yemen	0.5
Venezuela	5.5	Other Middle East Countries	0.2
Other South and Central American countries	0.1	Total Middle East	80.0
Total South and Central America	7.6	Algeria	4.5
Azerbaijan	1.3	Egypt	2.2
Denmark	<0.05	Libya	1.5
Germany	0.1	Nigeria	5.1
Italy	0.1	Other African Nations	1.2
Kazakhstan	1.9	Total Africa	14.5
Netherlands	1.1	Australia	3.8
Norway	2.0	Bangladesh	0.4
Poland	0.1	Brunei	0.3
Romania	0.1	China	3.1
Russian Federation	44.6	India	1.2
Turkmenistan	24.3	Indonesia	3.0
Ukraine	0.9	Malaysia	2.4
United Kingdom	0.2	Myanmar	0.2
Uzbekistan	1.6	Pakistan	0.8
Other Europe and Eurasian countries	0.3	Papua New Guinea	0.4
Total Europe and Eurasia	78.7	Thailand	0.3
		Vietnam	0.6
		Other Asia Pacific Nations	0.3
		Total Asia Pacific	16.8
Total World 208.4

Data from Ref. [9].

Table 13.2. Technically Recoverable Natural Gas Resources/(10¹²  m³).

Region	Conventional	Unconventional				Total
		Tight Gas	Shale Gas	Coal bed Methane	Sub-total
East Europe/Eurasia	144	11	12	20	44	187
Middle East	125	9	4	–	12	137
Asia Pacific	43	21	57	16	94	137
OECD Americas	47	11	47	9	67	114
Africa	49	10	30	0	40	88
Latin America	32	15	33	–	48	80
OECD Europe	24	4	16	2	22	46
World	462	81	200	47	328	790

Data from Ref. [8].

Most of the conventional reserves exist in Eastern Europe and the Middle East, while Asia Pacific and North America hold the majority of the unconventional reserves. Of all the other countries, Russia has the largest share of reserves followed by Iran, Qatar and Turkmenistan, while the highest production of natural gas has been in the United States and the Russian Federation [7,8,10,11]. Table 13.3 lists worldwide consumption and production of natural gas by regions.

Table 13.3. Worldwide and Regional Annual Production and Consumption in 2010/(10⁹  m³).

Region	Production	Consumption
North America	840	760
Central and South America	740	210
Western Europe	460	410
Central and Eastern Europe	460	630
Africa	240	100
Middle East	220	400
Asia and Oceania	160	530
Worldwide	3120	3040

Data from Refs. [10,11].

The United States and the Russian federation are the countries with the largest consumption of natural gas, and worldwide consumption is projected to grow at a rate of 1.6   % annually through to 2035. These estimates of consumption, along with the increase in proven natural gas reserves and technological developments such as hydraulic fracturing that enable greater extraction from unconventional reservoirs, have led to estimates that the natural gas reserves will be able to satisfy energy demands for the next seven to eight decades [8]. It must be noted, however, that there is necessarily a large degree of uncertainty in the projections of production in the future, especially from natural gas hydrates and hydraulic fracturing in unconventional reservoirs. Commercial production of natural gas from hydrates is not significant now, but may increase in the future. Finally, consumption profiles may vary in the future depending on the extent to which the world embraces fuels from renewable sources.

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Coalbed Methane

Caineng Zou , in Unconventional Petroleum Geology, 2013

Section 4 Forming and Distributing Coalbed Methane

1 Implication of Coalbed Methane and Its Boundaries

Coalbed methane is an unconventional natural gas, and its reservoir has distinctly different characteristics compared with the conventional natural gas reservoir. Therefore, we should not directly apply the concepts of a natural gas reservoir to coalbed methane. In this book, the coalbed methane reservoir is defined as the coal-bearing series having similar geological factors, a relatively independent fluid system, and certain resources dominated by coalbed methane in the adsorbed state. Since coalbed methane reservoirs are distributed as extensively and continuously as other unconventional gas reservoirs, they are also a type of continuous gas reservoir.

Based on the systematic analysis of typical coalbed methane in China and abroad, the boundary system of coalbed methane is divided into five types: hydrodynamic boundary, aero-oxidation zone boundary, fault boundary, physical property boundary, and lithological boundary.

In the hydrodynamic boundary, coalbed methane in its adsorbed state predominantly occurs within the hydrostatic action of the underground water table, and the basic units for coalbed methane accumulation are controlled by the recharge, migration, detention, and drainage of the water table. Therefore, the hydrodynamic conditions of the underground water table is one of the decisive factors for accumulation and reservoir formation of coalbed methane. The hydrodynamic boundary can be further subdivided into two kinds: underground water divide and hydrodynamic blockage. The existence of an underground water divide separates the coalbed methane at both sides in different units of fluid flow. This type of boundary exists in east-central Utah in the United States and in the southern Qinshui Basin in China. Formation of an underground water divide is controlled by structure, generally at the axial part of an anticline. A hydrodynamic blockage boundary is the most common coalbed methane boundary, existing in almost all coalbed methane systems. It occurs mainly as water recharging along the outcrop of a coal bed, then migrating deeper and forming a water table at a certain depth, enabling accumulation of coalbed methane in the detention zone. To retain a certain amount of coalbed methane in a reservoir, it is necessary to have a certain pressure in the reservoir—that is, a certain elevation of the underground hydrostatic table, which corresponds to reservoir pressure. Therefore, we know that the hydrodynamic boundary is the boundary indirectly reflecting the gas-bearing amount, and also a dynamic boundary that changes as the underground water table changes.

The weathered and oxidized zone boundary is a boundary dependent on the composition of coalbed methane components. As the underground water table declines, coalbed methane is dissipated along outcrops and mixes with air, changing the composition of coalbed methane components and resulting in a decrease of methane content and increase of carbon dioxide and nitrogen contents. Generally, methane concentration of 80% is regarded as the lower limit of the weathered and oxidized zone. For example, in the southern Qinshui Basin, the methane content drops abruptly above the boundary of the weathered and oxidized zone (Figure 4-19). Therefore, to some extent the weathered and oxidized zone is an artificial boundary.

FIGURE 4-19. Determination of the weathered and oxidized zone boundary in the southern Qinshui Basin.

Faults are an important lateral boundary for coalbed methane, and can be identified as either closed or open faults. A closed fault occurs when the displacement pressure of the rock body in the fault zone is greater than the reservoir pressure. The smearing action of mudstone reinforces the closing ability of a fault, and the lithological composition at both sides of a fault differ due to fault throw and the displacement pressure in rock beds butted up to the coal reservoir. Also, the strong cataclasis of grains and diagenetic cementation can close up faults. The closing of an open fault depends on the hydrostatic pressure in the fault belt. High hydrostatic pressure favors the retention of coalbed methane; otherwise, coalbed gas dissipation results. It acts identically to the mechanism of the hydrodynamic blockage boundary.

A physical property boundary occurs when a coal body is recrystallized into mylonitic coal by the action of tectonic stress, and its physical properties degrade and the displacement pressure increases remarkably. As a result, the diffusion and migration of coalbed methane is blocked. Also, mylonitic coal has a high gas content that increases the reservoir pressure, thereby blocking the concentrational diffusion, migration, and dissipation of coalbed methane in the adjacent coal bodies. This type of boundary is cogenetic usually with fault boundaries and is distributed along the fault belt, having significance for the closing of a fault. Faults with different natures and the fault upthrow and downthrow tend to create coal bodies with different widths and various recrystallizations. Increasing attention has been paid to this type of boundary along with the development of coalbed methane and the coal mining progress.

A lithological boundary refers to the boundary at a pinchout zone of a coal bed. Two cases can be described in this type of boundary: one is that the lithology at the pinchout zone of a coal bed has high permeability and low displacement pressure, such as sandstone or fractured porous limestone. In this case, the accumulation of coalbed methane is unlikely, as gas is subject to escape rather than be retained. Another is that the lithology at the pinchout zone of a coal bed has low permeability, such as mudstone or siltstone, which have high displacement pressures and are favorable to coalbed methane retention.

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Offshore Geology and Operations

James G. Speight , in Subsea and Deepwater Oil and Gas Science and Technology, 2015

2.6.2 Modern Perspectives

The modern offshore crude oil and natural gas industry provides a substantial amount the crude oil and natural gas supply of the United States. Large crude oil natural gas reservoirs are found under the waters of the Gulf of Mexico (offshore from Louisiana and Texas), California, and Alaska. Other notable world-wide offshore fields are located in the North Sea—which is an extremely harsh environment—as well as in the Campos and Santos basin off the coast of Brazil, several fields off West Africa (notably offshore Nigeria and offshore Angola) as well as offshore fields in South East Asia and the crude oil natural gas fields in the Barents Sea (located north of Norway and Russia).

As exploration and production of offshore oil and gas have advanced, the focus has evolved to deep-water sources (Chapter 6). It was once generally believed that oil could not be trapped in deep water, since reservoir rocks such as limestone and sandstone were not thought to occur in these deep waters but this line of thinking has been proven to be erroneous—sandstones formations do indeed occur in deep water. In fact, during the past 75 million years, the Gulf Coast has been progressively pushed further southward as sediments have piled up along the shore, moved here by the Mississippi River and other smaller streams. Furthermore, since the Gulf of Mexico has been a depositional basin for so long, there has been no shortage of mostly sandstone, siltstone, and shale that have been deposited. In fact, the deposition of potential reservoir rock continues to be deposited by the Mississippi River as sand and mud into the ocean is transported into the Gulf of Mexico. As the river shifts back and forth (avulsing), sand is deposited in some areas, whereas clay is deposited in other areas. These (and other) factors have created the sedimentary rocks that currently exist along the Gulf Coast, both above ground, and in the subsurface.

Since the 1950s, offshore structures have evolved to take on the size and appearance of small villages and the use of these structures for the exploration and production of offshore crude oil and natural gas reserves has increased to use in most continental shelf areas of the world. Offshore structures for the purpose of producing crude oil and natural gas reserves are located in waters ranging from shallow water to water approximately 10,000 ft deep. Subsea production facilities are being considered such that no surface structure is necessary, but current subsea wells are connected to surface producing offshore structure using flowlines, umbilicals, and manifolds. Undersea pipelines transport crude oil natural gas to the shore and are another type of offshore structure that are designed and installed to provide a means of transporting energy resources to land. Along with the expansion of offshore activities offshore, there has been a trend in the industry to a rationalization to lessen the risk of failure at all levels of the exploration process, and stimulating resource replacement and growth through the efficient exploration of basins and plays (Morbey, 1996).

At the same time, new opportunities have opened for the success of exploration activities success passive margin coastal basins, many have which had been considered to be beyond peak production capabilities. The recent ability for companies to explore beyond the known offshore in deeper waters and passive margin exploration has moved into deeper waters of the South Atlantic off West Africa, as well as the North Atlantic West of the Shetlands. These areas offer a high-risk, high-reward challenge, and drilling environments in need of innovative new E&P technology and creative initial exploration strategies (Morbey, 1996).

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Volcanic Gas Reservoir Characteristics and Models

Qiquan Ran , ... Qiang Wang , in Development of Volcanic Gas Reservoirs, 2019

4.1.2.4 Compound Trap Volcanic Gas Reservoir

Under the combined volcanic eruption effects, structure and diagenesis in the rock formation and evolution period, compound traps generally formed with the structural traps properties, internal structural traps and lithologic traps at the same time. Therefore, in compound trap volcanic reservoirs, natural gas accumulates at the traps in effective reservoirs, which are formed through the compound segmentation and impermeable lithology sheltering and structures, forming compound trap volcanic gas reservoirs.

Compound trap volcanic gas reservoirs have the following features. First, the reservoir distribution is under the control of compound structures, internal structures, and lithology, and main traps types may vary at different positions. Second, the reservoirs type and shape change quickly at different positions and the connectivity is largely different. Third, there are various pore types, cavities, and fractures in reservoirs, and their types vary at different positions. Several storage-seepage modes develop in reservoirs, such as the single-pore type, fracture-pore type, pore-fracture type, and fracture type. The reservoir scale is controlled by the compound trap scale. The reservoirs usually have no unified gas-water interfaces and pressure systems.

For compound trap volcanic gas reservoirs, the production volume, pressure and rate-maintenance ability are under the structural position joint control, reservoir properties, gas content, and reservoir scale. For the reservoirs at high structural positions, which also have good physical properties and high gas content, the gas production volume is high and the pressure keeps stable during production. For the reservoirs at low structural positions, which have poor physical properties and low gas content, the production volume is low and gas is produced together with water. The total volume and pressure decrease fast during production.

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