Thursday, August 29, 2019

Coalbed Methane

Natural gas is often located in the same reservoir as with crude oil, but it can also be found trapped in gas reservoirs and within coal seams. The occurence of methane in coal seams is not a new discovery and methane (called firedamp by the miners because of its explosive nature) was known to coal miners for at least 150 years (or more) before it was rediscovered and developed as coalbed methane (Speight, 2013b). The gas occurs in the pores and cracks in the coal seam and is held there by underground water pressure. To extract the gas, a well is drilled into the coal seam and the water is pumped out (dewatering) which allows the gas to be released from the coal and brought to the surface.

Coalbed methane (sometime referred to as coalmine methane) is a generic term for the methane found in most coal seams. 

Coalbed methane is a gas formed as part of the geological process of coal generation and is contained in varying quantities within all coal. Coalbed methane is exceptionally pure compared to conventional natural gas, containing only very small proportions of higher molecular weight hydrocarbons such as ethane and butane and other gases (such as hydrogen sulfide and carbon dioxide). Coalbed gas is over 90% methane and, subject to gas composition, may be suitable for introduction into a commercial pipeline with little or no treatment (Rice, 1993; Speight, 2007).  Methane within coalbeds is not structurally trapped by overlying geologic strata, as in the geologic environments typical of conventional gas deposits. Only a small amount (on the order 5-10% v/v) of the coalbed methane is present as free gas within the joints and cleats of coalbeds. Most of the coalbed methane is contained within the coal itself (adsorbed to the sides of the small pores in the coal). 

As the coal forms, large quantities of methane-rich gas are produced and subsequently adsorbed onto (and within) the coal matrix. Because of its many natural cracks and fissures, as well as the porous nature , coal in the seam has a large internal surface area and can store much more gas than a conventional natural gas reservoir of similar rock volume. If a seam is disturbed, either during mining or by drilling into it before mining, methane is released from the surface of the coal. This methane then leaks into any open spaces such as fractures in the coal seam. In these cleats, the coalmine methane mixes with nitrogen and carbon dioxide (CO2). 

Boreholes or wells can be drilled into the seams to recover the methane. Large amounts of coal are found at shallow depths, where wells to recover the gas are relatively easy to drill at a relatively low cost. At greater depths, increased pressure may have closed the cleats, or minerals may have filled the cleats over time, lowering permeability and making it more difficult for the gas to move through the coal seam. Coalbed methane has been a hazard since mining began. To reduce any danger to coal miners, most effort is addresed at minimizing the presence of coalbed in the mine, predominantly by venting it to the atmosphere. 

In coalbeds (coal seams), methane (the primary of natural gas) is generally adsorbed to the coal rather than contained in the pore space or structurally trapped in the formation. Pumping the injected and native water out of the coalbeds after fracturing serves to depressurize the coal, thereby allowing the methane to desorb and flow into the well and to the surface. Methane has traditionally posed a hazard to underground coal miners, as the highly flammable gas is released during mining activities. Otherwise inaccessible coal seams can also be tapped to collect this gas, known as coalbed methane, by employing similar well-drilling and hydraulic fracturing techniques as are used in shale gas extraction.

The primary (or natural) permeability of coal is very low, typically ranging from 0.1 to 30 mD and, because coal is very weak (low modulus) material and cannot take much stress without fracturing, coal is almost always highly fractured and cleated. The resulting network of fractures commonly gives coalbeds a high secondary permeability (despite coal's typically low permeability). Groundwater, hydraulic-fracturing fluids, and methane gas can more easily flow through the network of fractures.  Because hydraulic fracturing generally enlarges preexisting fractures in addition to creating new fractures, this network of natural fractures is very important to the extraction of methane from the coal.

The gas from coal seams can be extracted by using technologies that are similar to those used to produce conventional gas, such as using wellbores. However, complexity arises from the fact that the coal seams are generally low permeability and tend to have a lower flow rate (or permeability) than  conventional gas systems, gas is only sourced from close to the well and as such a higher density of wells is required to develope a coalbed methane resource as an unconventional resource (such as tight gas) than a conventional gas resource. 

Technoogies such as horizontal and multilateral drilling with hydraulic fracturing are sometimes used to create longer, more open channels that enhance well productivity but not all coal seam gas wells require application of this technique. Water present in coal seam, either naturally occuring or introduced during the fracturing operation, is usually removed to reduce the pressure sufficiently to allow the gas to be released, which leads to additional operational requirements, increased investment, and environmental concerns. 











Natural Gas Condensate

Natural Gas condensate (gas condensate, natural gasoline) is a low-density low-viscosity mixture of hydrocarbon liquids that may be present as gaseous components under reservoir conditions and which occur in the raw natural gas produced from natural wells. The constituents of condensate separate from the untreated (raw) gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas. Briefly, the dew point is the temperature to which a given volume of gas must be cooled, at constant barometric pressure, for vapor to condense into liquid. Thus, the dew point is the saturation point. 

On a worldwide scale, there are many gas-condensate reservoir and each has its own unique gas-condensate composition. However, in general, gas condensate has a spesific gravity on the order of ranging from 0.5 to 0.8 and is composed of hydrocarbons such as propane, butane, pentane, hexane, heptane and even octane, nonane and decane in some cases. In addition, the gas condensate may contain additional impurities such as hydrogen sulfide, thiols (mercaptans, RSH), carbon dioxide, cyclohexane (C6H12), and low molecular weight aromatics such as benzene (C6H6) , toluene (C6H5CH3), etc.

When condensation occurs in the reservoir, the phenomenon known as condensate blockage can halt flow of the liquids to the wellbore. Hydraulic fracturing is the most common mitigating technology in siliciclastic reservoirs (reservoirs composed of clastic rocks), and acidizing is used in carbonate reservoirs (Speight, 2016a). Briefly, clastic rocks are composed of fragments, or clasts, of preexisting minerals and rock. A clast is a fragment of geological detritus, chunks, and smaller grains of rock broken off other rocks by physical weathering. Geologist use the term clastic with reference to sedimentary rocks as well as to particles in sediment transport whether in suspension or as bed load, and in sedimentary deposits. 

In addition, production can be improved with less drawdown in the formation. For some gas-condensate fields, a lower drawdown means single-phase production above the dew point pressure can be extended for a longer time. However, hydraulic fracturing does not generate a permanent conduit past a condensate saturation buildup area. Once the pressure drops below the dew point, saturation will increase around the fracture, just as it did around the wellbore. Horizontal or inclined wells are also being used to increase contact area within formations. 




Thursday, August 8, 2019

Finding the Cracks in Master's Creek

Murray A-1 is a dual-lateral well drilled by OXY USA Inc. in the Cretaceous Austin Chalk formation, located in the Master's Creek field, Rapides Parish, Lousiana, USA. The Austin Chalk is a low-permeability formation that produces hydrocarbons from fractures, when present. Indications of fractures were seen from cuttings and gas shows obtained by mud loggers on a previous well. The intention was to drill this well perpendicular to the fracture planes to intersect multiple fractures and maximize production.








OXY wanted to record borehole images in the reservoir section for fracture evaluation. Fracture orientation would show if the well trajectory was optimal for intersecting the maximum number of fractures. Knowledge of fracture frequency, size and location along the horizontal section could be useful for future completion design, reservoir engineering and remedial work.

Ideally, the wireline FMI Fullbore Formation MicroImager tool would have been run, but practical considerations precluded this option. Wireline tools can be conveyed downhole by drillpipe or by coiled tubing in high-deviation or horizontal wells, but pressure-control requirements prevented the use of drillpipe conveyance in this case and coiled tubing was considered too costly. Also, calculations showed that helical coiled tubing lockup would occur before reaching the end of the long horizontal section. So OXY decided to try the RAB tool. 

 The first lateral well was drilled due north to cut assumed fracture planes at right angles. During drilling , images were recorded over about 2000 ft [600 m] of the 8 1/2 inch. horizontal hole. After each bit run the data were dumped to a surface workstation and examined using Fracview software.

Although the resolution of the RAB tool is not high enough to see microfractures, several individual major fractures and clusters of smaller fractures were clearly seen, providing enough evidence that the well trajectory was nearly perpendicular to the fracture trend.





Images of California 

Complex tectonic activity in southern California, USA, has continued throughout the Tertiary period to the present time. This activity influences offshore Miocene reservoirs where folding and tilting affect reservoir structure. Production is from fractured, cherty, dolomitic and siliceous zones through wellbores that are often drilled at high angle.

Wireline logs are run for formation evaluation and fracture and structural analysis-although in some cases they have to conveyed downhole on the TLC Tough Logging Conditions system.

The CDR Compensated Dual Resistivity tool was used to record resistivity and gamma ray logs for correlation while drilling. The oil company wanted to evaluate using the RAB tool primarily for correlation, but also wanted to assess the quality of images produced. In fact, it was the images that, in the end, generated the most interest.

Good-quality FMI logs were available, allowing direct comparison with RAB images. Both showed large-scale events, such as folded beds, that were several feet long, as well as regular bedding planes. However, beds less than a few inches thick were not seen clearly by RAB images. 







 Analysis of cores indicated wide distribution of fractures throughout the reservoir with apertures varying from less than 0.001 in. to 0.1 in. . The button electrodes that produce RAB images are large in comparison - 1 in. in diameter. However, even with low-resisitivy contrast across the fractures, the largest fractures or densest groups of fractures that appear on the FMI images were seen on the RAB images. The RAB tool could not replace FMI data.

What intrigued the oil company , however, was the possibility of calculating dips from RAB images. If this were successful, then the RAB tool could help resolve structural changes, such as crossing a fault, during drilling. The suggestion was taken up by Anadrill. With commercial software, dips were calculated from RAB images. Good agreement was found between RAB and FMI dips.

Dip correlation during drilling proved useful on subsequent California wells. Many have complex structures, and the absence of clear lithologic markers during drilling means that the structural position of wells may become uncertain. Currently, RAB image data are downloaded when drillpipe is pulled out of the hole for a new bit and dips are subsequently calculated. The data are used to determine if the well is on course for the highly fractured target area. 

 











Tuesday, August 6, 2019

Resistivity While Drilling - Images from the String

Resistivity measurements made while drilling are maturing to match the quality and diversity of their wireline counterparts. Recent advances include the development of multiple depth-of-investigation resistivity tools for examining invasion profiles, and button electrode tools capable of producing borehole images as the drillstring turns. 

It is hard to believe that logging while drilling (LWD) has come such a long way over the last decade. In the early 1980s, LWD measurements were restricted to simple resistivity curves and gamma ray logs, used more for correlation than formation evaluation. Gradually, sophisticated resistivity, density and neutron porosity tools have been added to the LWD arsenal. With the advent of high-deviation, horizontal and now slim multilateral wells, LWD measurements often provide the only means of evaluating reservoirs. The quality and diversity of LWD tools have continued to develop quickly to meet this demand. Today, applications include not only petrophysical analysis, but also geosteering and geological interpretation from LWD imaging. This article focuses on the latest LWD resistivity tools - the RAB Resistivity-at-the-Bit tool and the ARC5 Array Resistivity Compensated tool - and the images they produce.




 Geology From the Bit

Simply stated,  resistivity tools fall into two categories: laterolog tools that are suitable for logging in conductive muds, highly resistivity formations and resistive invasion; and induction tools which work best in highly conductive formations and can operate in conductive or nonconductive muds. The RAB tool falls into the first category although, stricly speaking, it is an electrode resistivity tool of which laterologs are one type. 

The RAB tool has four main features: 
  • toroidal transmitters that generate axial current- a technique highly suited to LWD resistivity tools
  • cyclindrical focusing that compensates for characteristic overshoots in resistivity readings at bed boundaries, allowing accurate true resistivity Rt determination and excellent axial resolution
  • bit resistivity that provides the earliest indication of reservoir penetration or arrival at a casing or coring point - also known as geostopping
  • azimuthal electrodes that produce a borehole image during rotary drilling.

This last feature allows the RAB tool to be used for geologic interpretation.

 Three 1 inch diameter buttons are mounted along the axis on one side of the RAB tool. Each button monitors radial current flow into the formation. As the drill string turns, these buttons scan the borehole wall, producing 56 resistivity measurements per rotation from each button. The data are processed and stored downhole for later retrieval when RAB tool is returned to the surface during a bit change. Once downloaded to the wellsite workstation, images can be produced and interpreted using standard geological applications like StructView Geoframe structural cross section software. 

Wellsite images allow geologist to quickly confirm the structural position of the well during drilling, permitting any necessary directional changes. Fracture identification helps optimize well direction for maximum production.