Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. 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. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically.
In the 1970s, the United States government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate. Eq. 7.1 clearly shows that the flow rate, q, is a function of permeability k; net pay thickness h; average reservoir pressure p; flowing pressure pwf; fluid properties β μ drainage area re; wellbore radius rw; and skin factor s. Thus, to choose a single value of permeability to define "tight ...
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft. The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area.
A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for coalbed methane (CBM). A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. Understanding the reservoir differences is key to successful evaluation and operation of a CBM project. Coal is a chemically complex, combustible solid consisting of a mixture of altered plant remains. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Type refers to the variety of organic constituents.
Core analyses are a critical part of analyzing CBM reservoirs to determine gas saturations. Coal cores must be placed in desorption canisters and heated to reservoir temperature. As the coal desorbs, gases are captured, and both their volume and composition are determined. Desorption continues for up to several months until the rate at which gas is being liberated from the coal becomes very small.
This article discusses the geology, depositional setting, and hydrogeology of promising CBM areas, along with a discussion of data sources that can help in evaluation of prospects. Foreland basins are flexural troughs that form in front of rising mountain belts. These basins, which include the Black Warrior and San Juan basins of the U.S., have provided more than 90% of the world's coal gas production to date. Cratonic basins such as the Williston basin, which straddles the U.S./Canadian border, are simple structural depressions that favor the deposition of widespread, continuous coal seams. Intermontane basins, which are common in the Appalachian Mountains of the eastern U.S., form within mountain belts and often are structurally complex, resulting in a more heterogeneous coal distribution.
Production and proved reserves in the Permian Basin’s Wolfcamp Shale and Bone Spring Formation are reaching new heights, and a new assessment from the US Geological Survey indicates the industry is just scratching the subsurface when it comes to what may be technically recoverable. Major oil discoveries by Armstrong Oil & Gas and ConocoPhillips have compelled the US Department of the Interior to reassess its estimate of undiscovered, technically recoverable resources in parts of Alaska. The list of the biggest gas plays in the US is being revised as the US Geological Survey creates new estimates based on additional drilling results and available rock samples. New at Number 2 is the Mancos Shale on the Western Slope of the Rockies with 66 Tcf in recoverable reserves.
The chief upstream strategist of IHS Markit said in a recent presentation that oil exploration must improve its ability to deliver value and better communicate that value to the financial community. New ways of thinking about exploration opportunities are needed. Producers in Oklahoma’s newly opened Merge play are sitting atop a resource that rivals some major world gas fields and discoveries, Citizen Energy’s Geology CEO Greg Augsburger told the SPE Gulf Coast Section Business Development Group recently. The Austin Chalk play could go through a revival if the industry can view the formation through “a fresh set of eyes,” says EnerVest’s Tony Maranto. Dimethyl-ether (DME) -enhanced waterflood (DEW) is a process in which DME is added to injection water and, upon injection, preferentially partitions into the remaining oil.