Thursday, October 17, 2019

Tight Gas chapter 2

By definition, shale gas is the hydrocarbon present in organic rich, fine-grained, sedimentary rocks (shale and associated lithofacies). The gas is generated and stored in situ in gas shale as both adsorbed gas(on organic matter) and free gas (in fractures or pores). As such, shale containing gas is a self-sourced reservoir. Low-permeable shale requires extensive fractrues (natural or induced) to produce commercial quantities of gas.

Shale is a very fine-grained sedimentary rock, which is easily breakable into thin, parallel layers. It is a very soft rock, but it does not disintegrate when it becomes wet. The shale formations can contain natural gas, usually when two thick, black shale deposits sandwich a thinner area of shale. Because of some of the properties of the shale deposits, the extraction of natural gas from shale formations is more difficult and perhaps more expensive than that of conventional natural gas. Shale basins are scattered across the United States. 

There are several types of unconventional gas resources that are currently produced: (1) deep natural gas - natural gas that exists in deposits very far underground, beyond "conventional" drilling depths, typically 15,000 ft or more, 

(2) shale gas- natural gas that occurs in low-permeability formations, (3) tight natural gas- natural gas that occurs in low-permeability shale formations , (4) geopressurized zones - natural underground formations that are under unusually high pressure for their depth, (5) Coalbed methane- natural gas that occurs in conjunction with coal seams, and (6) methane hydrates- natural gas that occurs at low-temperature and high-pressure regions such as the sea bed and is made up of a lattice of frozen water, which forms a cage around the methane. 

Coalbed methane is produced from wells drilled into coal seams which act as source and reservoir to the produced gas (Speight, 2013). These wells often produce water in the initial production phase, as well as natural gas. Economic coalbed methane reservoirs are normally shallow, as the coal  matrix tends to have insufficient strength to maintain porosity at depth.

Tuesday, October 15, 2019

Tight Gas

Tight gas describes natural gas that has migrated into a reservoir rock with high porosity but low permeability. This type of reservoir is not usually associated with oil and commonly require horizontal drilling and hydraulic fracturing to increase well output to cost-effective levels. In general, the same drilling and completion technology that is effective with shale gas can also be used to access and extract tight gas. 

Tight gas is the fastest growing natural gas resource in the United States and worldwide as a result of several recent development (Nehring, 2008). Advances in horizontal drilling technology allow a single well to pass through larger volumes of a shale gas reservoir and, thus, produce more gas. The development of hydraulic-fracturing technology has also improved access to shale gas deposits. This process requires injecting large volumes of water mixed with sand and fluid chemicals into the well at high pressure to fracture the rock, increasing permeability and production rates

 To extract tight gas, a production well is drilled vertically until it reaches the shale formation, at which point the wellbore turns to follow the shale horizontally. As drilling proceeds, the portion of the well within the shale is lined with steel tubing (casing). After drilling is completed,small explosive charges are detonated to create holes in the casing at intervals where hydraulic fracturing is to occur. In a hydraulic-fracturing operation, the fracturing fluid is pumped in at a carefully controlled pressure to fracture the rock out to several hundred feet from the well. Sand mixed with the fracturing fluid acts to prop these cracks open when the fluids are subsequently pumped out.  After fracturing, gas will flow into the wellbore and up to the surface, where it is collected for processing and sales.

Shale gas is natural gas produced from shale formations that typically function as both the reservoir and source rocks for the natural gas. In terms of chemical makeup, shale gas is typically a dry gas composed primarily of methane (60-95 %v/v) , but some formations do produce wet gas.The Antrim and New Albany plays have typically produced water and gas. Gas shale formations are organic-rich shale formations that were previously regarded only as source rocks and seals for gas accumulating in the strata near sandstone and carbonate reservoirs of traditional onshore gas development. 

Thursday, October 3, 2019

Tight Oil chapter 5

Oil from tight shale formation is characterized by low-asphaltene content, low-sulfur content, and a significant molecular weight distribution of the paraffinic wax content (Speight, 2014a, 2015a). Paraffin carbon chains of C10-C60 have been found, with some shale oils containing carbon chains up to C72. To control deposition and plugging in formations due to paraffins, the dispersants are commonly used. In upstream applications, these paraffin dispersants are applied as part of multifunctional additive packages where asphaltene stability and corrosion control are also addressed simultaneously (Speight, 2014). In addition, scale deposits of calcite (CaCo3), other carbonate minerals (minerals containing the carbonate ion, CO3 2-) and silicate minerals (minerals classified on the basis of the structure of the silicate group, which contains different rations of silicon and oxygen) must be controlled during production or plugging problem arise. 

A wide range of scale additives is available which can be highly effective when selected appropriately. Depending the nature of the well  and the operational conditions, a specific chemistry is recommended or blends of products are used to address scale deposition.

Another challenge encountered with oil from tight shale formations- many of which have been identified but undeveloped - is the general lack of transportation infrastructure. Rapid distribution of the crude oil to the refineries is necessary to maintain consistent refinery throughput- a necessary aspect of refinery design. 

Finally, the properties of tight oil are highly variable. Density and other properties can show wide variation, even within the same field. The Bakken crude is light and sweet with an API of 42 degrees and a sulfur content of 0.19% w/w. Similarly, Eagle Ford is a light sweet feed, with a sulfur content of approximately 0.1% w/w and with published API gravity between 40 and 62 degrees API.

Paraffin waxes are present in tight oil and remain on the walls of railcars, tank walls, and piping. The waxes are also known to foul the preheat sections of crude heat exchanger (before they are removed in the crude desalter). Paraffin waxes that stick to piping and vessel walls can trap amines against the wall which can create localized corrosion. 

 In many refineries, blending two or more crude oils as the refinery feedstock is now standard operating procedure which allows the refiner to achieve the right balance of feedstock qualities. However, the blending of the different crue oils may cause problems if the crude oils being mixed are incompatible (Speight,2014a). When crude oils are incompatible, there is increased deposition of the asphaltene constituents (Speight,2014a) which accelerates fouling in the heat exchanger train downstream of the crude desalter.

Thursday, September 26, 2019

Tight Oil Chapter 4

Success in extracting crude oil and natural gas from shale reservoirs depends largely on the hydraulic fracturing process (Speight, 2016b) that requires an understanding of the mechanical properties of the subject and confining formaitons. In hydraulic-fracturing design, Young's modulus is a criterion used to determine the most-appropriate fracturing fluid and other design considerations. Young's modulus provides an indication of the fracture conductivity that can be expected under the width and embedment considerations. Without adequate fracture conductivity, production from the hydraulic fracture will be minimal or nonexistent (Akrad et al., 2011). 

Typical of the crude oil from tight formations (tight oil- tight light oil and tight shale oil have been suggested as alternate terms) is the Bakken crude oil which is a light highly volatile crude oil. Briefly, Bakken crude oil is a light sweet (low-sulfur) crude oil that has a relatively high proportion of volatile constituents. The production of the oil also yields a significant amount of volatile gases (including propane and butane) and low-boiling liquids (such as pentane and natural gasoline), which are often referred to collectively as (low boiling or light) naphtha. 

By definition, natural gasoline (sometime also referred to as gas condensate) is a mixture of low-boiling liquid hydrocarbons isolate from crude oil and natural gas wells suitable for blending with light naphtha (light naphtha) can become extremely explosive, even at relatively low ambient-temperatures. 

Some of these gases may be burned off (flared) at the field well-head, but others remain in the liquid products extracted from the well (Speight, 2014a).

Bakken crude oil is considered to be a low-sulfur (sweet) crude oil and there have been increasing observations of elevated levels of hydrogen sulfide (H2S) in the oil. Hydrogen sulfide is a toxic, highly flammable, corrosive, explosive gas (hydrogen sulfide) and there have been increasing observations of elevated levels of hydrogen sulfide in Bakken oil. Thus, the liquids stream produced from the Bakken formation will include the crude oil, the low-boiling liquids, and gases that were not flared, along with the materials and byproducts of the hydraulic-fracturing process. 

Tuesday, September 24, 2019

Tight Oil Chapter 3

The most notable tight oil plays in North America include the Bakken shale, the Niobrara formation, the Barnett shale, the Eagle Ford shale, and the Miocene Monterey play of California's San Joaquin Basin in the United States, and the Cardium play in Alberta. In many of these tight formations, the existence of large quantities of oil has been known for decades and efforts to commercially produce those resources have occured sporadically with typically disappointing results. However, starting in the mid-2000s, advancements in well-drilling and stimulation technologies combined with high oil prices have turned tight oil resources into one of the most actively explored and produced targets in North America. 

Furthermore, of the tight oil plays, perhaps the best understood is the Bakken which straddles the border between Canada and the United States in North Dakota, Montana, and Saskatchewan. Much of what is known about the exploitation of tight oil resources comes from industry experiences in the Bakken and the prediction of future tight oil resource development described in this study are largely based on that knowledge. The Bakken tight oil play historically  includes three zones, or members, within the Bakken Formation. 

The upper and lower members of the Bakken are organic-rich shales which serve as oil source rocks, while the rocks of the middle member may be siltstone formations, sandstone formations, or carbonate formations that are also typically characterized by low permeability and high oil content. Since 2008 the Three Forks Formation, another tight oil-rich formation which directly underlies the lower Bakken shale, has also yielded highly productive oil wells. Drilling, completion, and stimulation strategies for wells in the Three Forks Formation are similar to those in the Bakken and the light, sweet crude oil that is produced from both plays has been geochemically determined to be essentially identical. Generally, the Three Forks Formation is considered to be part of the Bakken play, though the authors of published works will sometimes refer to it as the Bakken-Three Forks play.

Other known tight formations (on a worldwide basis) include the R'Mah Formation in Syria, the Sargelu Formation in the northern Persian Gulf region, the Athel Formation in Oman, the Bazhenov formaiton and Achimov Formation in West Siberia, Russia, the Coober Pedy in Australia, the Chicontepex formation in Mexico, and the Vaca Muerta field in Argentina (US EIA, 2011, 2013). However, tight oil formations are heterogeneous and vary widely over relatively short distances. Thus, even in a single horizontal drill hole, the amount of oil recovered may vary as may recovery within a field or even between adjacent wells. This makes evaluation of shale plays and decisions regarding the profitability of wells on a particular lease difficult and a tight reservoir which contains only crude oil (without natural gas as the pressurizing agent) cannot be economically produced (US EIA, 2011, 2013).

Tight Oil Chapter 2

The challenges associated with the production of crude oil from shale formation are a function of the compositional complexity and the varied geological formations where they are found. These oils are light, but they often contain high proportions of waxy constituents and, for the most part, reside in oil-wet formations. These phenomena create some of the predominant difficulties associated with crude oil extraction from the shale formations and include (1) scale formation, (2) salt deposition, (3) paraffin wax deposits, (4) destabilized asphaltene constituents, (5) equipment corrosion, and (6) bacteria growth. Thus, multicomponent chemical additives are added to the stimulation fluid to control these problems. 

 While crude oil from tight shale formations is characterized by a low content of asphaltene constituents and low-sulfur content, there can be a significant proportion of wax constituents in the oil. These constituents may exhibit a broad distribution of the molecular weight. For example, paraffin carbon chains of C10-C60 have been found and some tight crude oil may even have hydrocarbon carbon chains (wax) up to C72. While this may be a relief from recovery of high-asphaltene heavy oils, the joy is short-lived and the deposition of waxy constituents can cause as many problems as asphaltene incompatibility. To control deposition and plugging in formations due to paraffin, a variety of wax dispersants are available for use. In upstream applications, the paraffin wax dispersants are applied as part of multifunctional additive packages where, for convenience, asphaltene stability and corrosion control can also be addressed simultaneously. 

 Scale deposits of calcite , carbonates, and silicates must also be controlled during production or plugging problem arise. A wide range of scale additivies is available. These additives can be highly effective when selected appropriately. Depending the nature of the well and the operational conditions, a specific chemistry is recommended or blends of products are used to address scale deposition.

Monday, September 16, 2019

Tight Oil

In addition, oil from tight sandstone and from shale formations is another type of crude oil which varies from a gas-condensate type liquid to a highly volatile liquid.

Tight oil refers to the oil preserved in tight sandstone or tight carbonate rocks with low matrix permeability- in these reservoirs, the individual wells generally have no natural productivity or their natural productivity is lower than the lower limit of industrial oil flow, but industrial oil production can be obtained under certain economic conditions and technical measures. Such measures include acid fracturing, multistage fracturing , horizontal wells, and multilateral wells. 

The term light tight oil is also used to describe oil from shale reservoirs and tight reservoirs because the crude oil produced from these formations is light crude oil. The term light crude oil refers to low-density petroleum that flows freely at room temperature and these light oils have a higher proportion of light hydrocarbon fractions resulting in higher API gravities (between 37 and 42 degrees) (Speight, 2014a). However, the crude oil contained in shale reservoirs and in tight reservoirs will not flow to the wellbore without assistance from advanced drilling (such as horizontal drilling) and fracturing (hydraulic fracturing) techniques. 

There has been a tendency to refer to this oil as shale oil. This terminolgy is incorrect insofar as it is confusing and the use of such terminology should be discouraged as illogical since shale oil has been the name given to the distillate produced from oil shale by thermal decomposition. 

There has been the recent (and logical) suggestion that shale oil can be referred to as kerogen oil (IEA, 2013).

Monday, September 9, 2019

Tight Gas

In respect of the low permeability of these reservoirs, the gas must be developed via special techniques including stimulation by hydraulic fracturing (or fracking) in order to be produced commercially.

 Conventional  gas typically is found in reservoirs with permeability >1 mD and can be extracted via traditional techniques. A large proportion of the gas produced globally to date is conventional, and is relatively easy and inexpensive to extract. In contrast, unconventional gas is found in reservoirs with relatively low permeability (<1 mD) and hence cannot be extracted via conventional methods. However, there several types of unconventional gas resources that are currently under production but the three most common types are (1) shale gas, (2) tight gas, and (3) coalbed methane although methane hydrates are often included with these gases under the general umbrella of unconventional gas.

Generally, shale gas is a natural gas contained in predominantly fine, low-permeable sedimentary rocks, in consolidated clay-sized particles, at the scale of nanometers. Gas shale formations are organic-rich formations that are both source rock and reservoir. 

The expected value of permeability to gas flow is in the range of micro- to nanodarcy. The gas retained in such deposits is in the form of adsorbed material on rock, trapped in pore spaces and as an interbedding material with shales. Although the shale gas is usually very clean, it is hard to recover from deposits because of the structural complexity and low hydrodynamic conductivity of shales.

Shale gas is part of a continuum of unconventional gas that progresses from tight gas sand formations, tight gas shale formations to coalbed methane in which horizontal drilling and fracture stimulation technology  can enhance the natural fractures and recover gas from rocks with low permeability. Gas can be found in the pores and fractures of shales and also bound to the matrix, by a process known as adsorption, where the gas molecules adhre to the surfaces within the shale. During enhanced fracture stimulation drilling technology, fluid is pumped into the ground to make the reservoir more permeable, then the fractures are propped open by small particles, and can enable the released gas to flow at commercial rates.  By drilling multilateral horizontal wells followed by hydraulic fracturing, a greater rock volume can be accessed.

More specifically, shale gas is natural gas that is produced from a type of sedimentary rock derived from clastic sources often including mudstones or siltstones, which is known as shale. Clastic sedimentary rocks are composed of fragments (clasts) of preexisting rocks that have been eroded, transported, deposited, and lithified into new rocks. Shales contain organic material which was lain down along with the rock fragments. 

In areas where conventional resource plays are located, shales can be found in the underlying rock strata and can be the source of the hydrocarbons that have migrated upwards into the reservoir rock. Furthermore, a tight gas reservoir is commonly defined as is a rock with matrix porosity of 10% or less and permeability of 0.1 mD or less , exclusive of fracture permeability. 

Shale gas resource plays differ from conventional gas plays in that the shale acts as both the source for the gas and alsto the zone (also known as the reservoir) in which the gas is trapped. The very low permeability of the rock causes the rock to trap the gas and prevent it from migrating toward the surface. The gas can be held in natural fractures or pore spaces, or can be adsorped onto organic material. With the advancement of drilling and completion technology, this gas can be successfully exploited and extracted commercially as has been proven in various basins in North America.

Aside from permeability, the key properties of shales, when considering gas potential, are total organic carbon (TOC) and thermal maturity. The total organic content is the total amount of organic material (kerogen) present in the rock, expressed as a percentage by weight. Generally, the higher the total organic content, the better the potential for hydrocarbon generation. The thermal maturity of the rock is a measure of the degree to which organic matter contained in the rock has been heated over time and potentially converted into liquid and/or gaseous hydrocarbons. Thermal maturity is measured using vitrinite reflectance (Ro).

Because of the special techniques required for extraction, shale gas can be more expensive than conventional gas to extract. On the other hand, the inplace gas resource can be very large given the significant lateral extent and thickness of many shale formations. However, only a small portion of the total world resources of shale gas is theoretically producible and even less likely to be producible in a commercially viable manner. 

Sunday, September 8, 2019

Tight Gas andd Tight Oil

The terms tight oil and tight gas refer to crude oil (primarily light sweet crude oil) and natural gas, respectively, that are contained in formations such as shale or tight sandstone, where the low permeability of the formation makes it difficult for producers to extract the crude oil or natural gas except by unconventional techniques such as horizontal drilling and hydraulic fracturing. The terms unconventional oil and unconventional gas are umbrella terms for crude oil and natural gas that are produced by methods that do not meet the criteria for conventional production. Thus, the terms tight oil and tight gas refer to natural gas trapped in organic-rich rocks dominated by shale while tight gas trapped in in sandstone or limestone formations that exhibit very low permeability and such formations may also contain condenstate. Given the low permeability of these reservoirs, the gas must be developed via special drilling and production techniques including fracture stimulation (hydraulic fracturing) in order to be produced commercially (Gordon, 2012).

Unlike conventional mineral formations containing natural gas and crude oil reserves, shale and other tight formations have low permeability, which naturally limits the flow of natural gas and crude oil. In such formations, the natural gas and crude oil are held in largely unconnected pores and natural fractures. Hydraulic fracturing is the method commonly used to connect these pores and allow the gas to flow. The process of producing natural gas and crude oil from tight deposits involves many steps in addition to hydraulic fracturing, all of which involve potential environmental impacts (Speight, 2016b). 

Hydraulic fracturing is often misused as an umbrella term to include all of the steps involved in gas and oil production from shale formations and tight formations. These steps include road and well-pad construction, drilling the well, casing, perforating, hydraulic fracturing, completion, production, abandonnment, and reclamation. 

Tight sandstone formations and shale formations are heterogeneous and vary widely over relatively short distances. Thus, even in a single horizontal drill hole, the amount of gas or oil recovered may vary, as may recovery within a field or even between adjacent wells. This makes evaluation of tight plays (a play is a group of fields sharing geological similarities where the reservoir and the trap control the distribution of oil and gas). Because of the variability of the reservoirs- even reservoirs within a play- is different, decisions regarding the profitability of wells on a particular lease are difficult. Furthermore, the production of crude oil from tight formations requires that at least 15-20% v/v of the reservoir pore space is occupied by natural gas to provide the necessary reservoir energy to drive the oil toward the borehole; tight reservoirs which contain only oil cannot be economically produced (US EIA, 2013) 

In tight shale reservoirs and other tight reservoirs, there are areas known as sweet spots which are preferential targets for drilling and releasing the gas and oil. In these areas, the permeability of the formation is significantly higher than the typical permeability of the majority of the formations. The occurence of a sweet spot and the higher permeability may often result from open natural fractures, formed in the reservoir by natural stresses, which results in the creation of a dense pattern of fractures. Such fractures may have reclosed, filled in with other materials, or may still be open. However, a well that can be connected through hydraulic fracturing to open natural fracture systems can have a significant flow potential. 

Gas Hydrate

Methane hydrates is a resource in which a large amount of methane is trapped within a crystal structure of water, forming a solid similar to ice (Kvenvolden, 1995).. 

Natural gas hydrates are solids that form from a combination of water and one or more hydrocarbon or non-hydrocarbon gases. In physical appearance, gas hydrates resemble packed snow or ice. In a gas hydrate, the gas molecules (such as methane, hence the methane hydrates) are trapped within a cage-like crystal structure composed of water molecules. Gas hydrates are stable only under spesific conditions of pressure and temperature. Under the appropriate pressure, they can exist at temperatures significantly above the freezing point of water.  The maximum temperature at which gas hydrate can exist depends on pressure and gas composition. For example, methane plus water at 600 psia forms hydrate at 5 degree C, while at the same pressure, methane with 1% v/v propane forms a gas hydrate at 9.4 degree C. Hydrate stability can also be influenced by other factors, such as salinity (Edmonds et al, 1996).

Thursday, September 5, 2019

Fractured Reservoirs

  • Fractured reservoirs are reservoirs in which production and recovery is influenced to a greater or lesser extent by fractures. They can be subdivided into four different types (cf. Nelson , 2001; Allan & Qing Sun , 2003)
  • The variability in fracture network interconnectedness, and in the architecture and properties of the matrix, are the basic reasons that fractured reservoirs show a large variety of behaviors during hydrocarbon production. These large uncertainties make the appraisal, development and management of fractured reservoirs difficult. Failure to asses uncertainties properly leads to missed opportunities and low hydrocarbon recovery.
  • The special nature of fractured reservoirs lies in the interaction between, the (relatively) high pore volume , low permeability matrix (the storage domain) and the low pore volume, high permeability fracture system (the flow domain). This interaction is a function of matrix architecture and fracture network geometry, but also the mechanisms and physical processes that control the transfer of hydrocarbons from the matrix to the fracture network. The initial and developing stress state and the presence or absence of an aquifer also influence performance. 

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.

Tuesday, July 30, 2019

Mapping Porosity in Malaysia

Once thought to be useful primarily in carbonate reservoirs because of a more recognizable porosity-acoustic impedance relationship, inversion for porosity mapping has also proven powerful in sand reservoirs. PETRONAS Carigali, the upstream operating arm of the Malaysian national oil company, has used seismic inversion to optimize drilling locations in the Dulang West field in the Malay basin of the South China Sea.

The Dulang field has an estimated 850 million barrrels original oil in place (OOIP). In the first stage of development, more than 100 wells were drilled in the central area of the faulted anticlinal structure, producing from an oil and gas column of up to 150 m [492 ft] of stacked sandstones. The next stage of development focuses on the Dulang West portion, in which plans call for 25 wells from a 32-slot platform.

The four delineation wells indicate a reservoir too complex to understand from well data alone.The main reservoirs are fine-grained, discontinuous sands interbedded with shales and coals. The sand bodies are preferentially oriented, suggesting permeability anisotropy on the scale of the field. Porosity, permeability and their relationship to each other show great variability - for example, permeability can vary from 50 to several hundred millidarcies for a median porosity of 25%. In the central area developed earlier, close well spacing permitted property mapping from logs. But in Dulang West, engineers have relied on inversion of the 3D seismic data to extend information contained in the delineation wells to map porosity across the field.

After the poststack seismic and log data were tied at the right depths and inverted for acoustic impedance, log properties were tested for their correlation with the AI values at the respective well locations using the Log-Property Mapping module of the RM Reservoir Modeling software. Only porosity was found to correlate significantly with acoustic impedance, with a trend similar to that of the chalks of the East Hod field. Extending the log porosity values away from the four wells using the seismic inversion results as a guide produced a reservoir porosity map.


An integrated assessment of porosity and structure allowed interpreters to propose drilling locations. Areas of higher porosity in the south were deemed more promising than lower-porosity areas in fault block to the north. The well prognosis module of the RM system allowed several potential sites to be quickly investigated for reservoir quality and likely reserves.

The reservoir model built from the seismic data included not only the traditional aspect of reservoir structure, but also the total volume of porosity in each volume element of the seismic cube. This model was scaled up for input to a fluid-flow simulator. Permeability was distributed throughout the model by applying a porosity-permeability transform to the seismically guided porosity map. The new model provided a better estimation of production over a simulated seven-year period than that obtained by other methods.

In addition, areas of high acoustic impedance were interpreted to be shaly or to have poor reservoir development, enabling better placement of planned wells. Recent appraisal drilling southeast of well 6G-1.3 , testing oil potential downdip of gas inferred from an especially low AI anomaly, encountered 18 m [59 ft] of good quality, 18% porosity gross sand. Althought the sand was wet, agreement with the model was good, with 18.8 m [62 ft] and 19% porosity predicted. Two development wells, D1 and D2, further demonstrate the predictive power of the method. 


In some environments, seismic reflection amplitude variation with offset (AVO) can be used as a reservoir management tool to indicate hydrocarbon extent. The AVO technique relies on the observation - backed up by physics- that pore fluid imprints a signature on the amplitude of a seismic reflection. To see this signature, seismic data must be viewed at different angles of reflection. Depending on the type of pore fluid in the juxtaposed rock layers, the amplitude of the reflection may increase, decrease , or remain constant as the  as the reflection angle at the boundary increases. The incident angle of the seismic wave can be expressed in terms of offset, or distance , between seismic source and receiver - a congruent quantity more easily measured than an angle at some depth.

A common way to use AVO to characterize reservoirs is to identify a hydrocarbon AVO signature- for example, the AVO response of a gas reservoir- and comb the 3D seismic volume for other areas with similar signatures. This can result in discoveries of bypassed hydrocarbon as well as extension or delineation of existing reservoirs. The practice assumes that lithology does not have enough lateral variation to affect the seismic amplitudes, so that all AVO effects are due to changes in pore fluid type. The seismic data must be processed to preserve relative amplitudes, and also must be analyzed before stacking. 

Some lithologies show less obvious AVO sensitivity to pore fluid change than others. Carbonates and low-porosity sandstones tend to have less evident AVO signatures than high-porosity sandstones, and special care must be taken in applying the technology in these areas.

In an example from the mature BK field in the Gulf of Mexico, the successful incorporation of AVO analysis helped Oryx Energy Company engineers identify extensions of the reservoir that might have gone undrilled. The quality of the AVO results convinced management to free up money for drilling that had been allocated elsewhere.

The BK field lies off the flank of a shallow salt and shale diaper in 5 m of water near the Lousiana Gulf Coast. The reservoir, discovered in the late 1940s, has produced 300 billion cubic feet (Bcf) of gas. The map of the 5000-m [16,400-ft] deep structure had ben constructed primarily with well control, and the new 78-km2 survey, designed to provide incremental structural and stratigraphic information, changed the structural map significantly.

AVO analysis was introduced to better delineate the gas reservoir and reduce risk in choosing drilling locations. The analysis required a seismic cube for two different families of offsets. Data processing followed the same sequence as for the full 3D cube, except the data were separated into a near offset volume with offset ranges from zero to 3800 m and a far offset volume with offset from 3800 to 5800 m. 

Forward modeling using logs from producing wells indicated the gas zones have an AVO signature of amplitude increasing with offset. Interpretation consisted of finding other areas in which the near-offset volume has low amplitudes and the far-offset volume has higher amplitudes. 

The technique is demonstrated on a pair of seismic lines exctracted from the 3D volume. The AVO signature on Line 1215 at the gas-producing well BK-15 is the standard to which Line 1235 is compared to determine the likelihood of hitting gas at the proposed location BK-16. A color-coding system was devised to discriminate increasing AVO trends from decreasing ones. Results of the analysis show the BK-16 location to be similar to, and perhaps even more promising than, the producer BK-15. 

Initial production from the BK-16 well was 15.4 MMcf/D and 210 barrels of condensate per day from 25 m [82 ft] of 20% porosity sand. Sand quality is better than that found in the BK-15 well, refuting speculation that sand quality degrades to the northwest. And following the BK-16 well, two additional successful wells have been drilled within the region of AVO gas signature.