Bakken Formation: News, Map, Videos and Information SourcesThroughout history, most great oil and gas fields were "discovered". The Bakken was "unlocked" through innovation.

What is the Bakken Formation?

The Bakken Formation is one of the largest contiguous deposits of oil and natural gas in the United States. It is an interbedded sequence of blackshale,siltstoneandsandstonethat underlies large areas of northwestern North Dakota, northeastern Montana, southern Saskatchewan and southwestern Manitoba.Bakken-Formation

DieBakken-Formationist einegeologische Formationaus dem sptenDevonbis frhenMississippium. Sie umfasst etwa 520.000km unter der Oberflche desWilliston-Beckens, welches Teile vonMontana,North DakotaundSaskatchewanumfasst. Die Formation wurde erstmals 1953 durch dem Geologen J. W. Nordquist beschrieben und wurde benannt nach Henry Bakken, einem Bauern ausTioga, North Dakota, auf dessen Land die Formation entdeckt wurde.[1]

HYPERLINK "http://de.wikipedia.org/wiki/Bakken-Formation" \l "cite_note-2" \t "_self" [2]Bakken Formation Map

The Bakken Formation underlies large areas of northwestern North Dakota, northeastern Montana, southern Saskatchewan and southwestern Manitoba. The green area on this map shows the approximate extent of the Bakken oil play.

The Bakken was deposited within the Williston Basin and is Late Devonian to Early Mississippian in age. The Bakken Formation consists of a lower shale member, a middle sandstone member and an upper shale member. The shales are organic-rich and of marine origin. They are rich source rocks foroil and natural gas. All three members of the Bakken Formation have been known to yield oil and natural gas.

Just a few years ago in 2007, the Bakken was considered a marginal to submarginal resource because the oil and natural gas are are locked in a rock formation with a low permeability. However, advances in drilling and recovery technology such as horizontal drilling and hydrofracturing have transformed the Bakken into a prolific oil and natural gas producer.

Since then the Bakken has propelled North Dakota oil production to record levels, moving the state to the position of #2 oil producer in the United States. The only state that produces more crude oil is Texas.

The Bakken Formation has also given a major boost to the North Dakota economy and reduced unemployment in the state to very low levels. The Bakken resources is expected to be productive for decades and make a major contribution to the energy independence of the United States.

Bakken Drilling

Advances in drilling and well stimulation made the Bakken Formation a viable oil and gas resource.Horizontal drillingenables wells to have a much longer "pay zone" than a traditional vertical well.Hydraulic fracturing produces porosity in the rock unit that facilitates movement of oil or gas to the well. Together, these methods allow asinglewell to drain a much larger volume of rock and more efficiently recover the oil and gas resource.

TheUSGS Assessment for the Bakken Formationestimated mean undiscovered volumes of 3.65 billion barrels of oil, 1.85 trillion cubic feet of associated / dissolved natural gas, and 148 million barrels of natural gas liquids in the United States portion of the Bakken Formation. These resources are contained within both conventional and unconventional reservoirs. The Bakken Formation in Canada contains additional resources and has been called one of the largest oil fields in Canada.

In early 2008 only a few wells had been drilled into the Bakken and its viability as a resource was uncertain. However, by the end of 2012, thousands of successful wells made it one of the most importantcrude oilsources in the history of North America.

Throughout history, most great oil and gas fields have been discovered. The Bakken Formation was unlocked through innovation.DOC 2

Bakken Shale Oil Formation

Bakken News Fri, May 23, 2014Oasis on Track to Achieve Bakken Production Targets for 2014 Wed, May 21, 2014Hess Production To Soar in Bakken By the End of 2014 Mon, May 19, 2014Bakken Shale Rig Count Increases by One to 182 Fri, May 16, 2014AFPM Study Finds Bakken Crude Meets Current Safety Standards for Rail Car Design Wed, May 14, 2014Magnum Hunter Resources Bakken First Quarter Update Mon, May 12, 2014Bakken Shale Rig Count Decreases by One to 181 Fri, May 9, 2014Halcn Resources Sets New Operations Records in the Williston BasinTheBakken Shaleranks as one of the largest oil developments in the U.S. in the past 40 years. The play has single-handedly driven North Dakotas oil production to levels four times higher than previous peaks in the 1980s. As of 2012, ND is second to Texas in terms of oil production and boasts the lowest unemployment rate in the country at ~3%.

The Bakken Shale Play is located in Eastern Montana and Western North Dakota, as well as parts of Saskatchewan and Manitoba in the Williston Basin. Oil was initially discovered in the Bakken play in 1951, but was not commercial on a large scale until the past ten years. The advent of modern horizontal drilling and hydraulic fracturing helps make Bakken oil production economic. The U.S. GeologicalSurveyhas estimated the Bakken Shale Formation could yield 4.3 billion barrels of oil and estimates from Continental Resources stretch as high as 40 billion barrels.

The name Bakken originates from a North Dakota farmer, Henry Bakken, who owned the land where the first well encountered the Bakken formation.

Bakken Shale Geology

Bakken Shale Map | Click to Enlarge

The Bakken Shale is a rock formation that was deposited in the late Devonian, early Mississippian age. The formation consists of three layers: an upper shale layer, middle dolomite, and a lower layer of shale. The shale layers are petroleum source rocks as well as seals for the layer known as the Three Forks (dolomite) or Sanish (sands) formations.

A 2008 USGS study pegged recoverable reserves at approximately 4 billion barrels and a 2010 NDIC study estimates the underlying Three Forks formation could yield an additional 2 billion barrels. Both estimates are likely conservative. The Bakken is estimated to hold as much as 400 billion barrels of oil equivalent in place. Four billion barrels only represents 1% of the oil estimated to be in place, while current recovery estimates range from 3-10%. Continental Resources has publicly expressed beliefs the Bakken will yield anywhere from 24-40 billion barrels. If youd like to read more, visit ourBakken Geologypage for additional information.

Bakken Shale Companies

While theBakkenexperienced multiple small scale booms over the past 60 years, it was a horizontal well drilled in the Elm Coulee Field by apartnershipbetween Lyco Energy and Halliburton that incited our modern boom. The Elm Coulee was proven economic in 2003 and operators began expanding into North Dakota after EOGs Parshall discovery in 2006. The play was driven by innovations and small to mid size exploration and production companies. If youd like to read more about the various operators in the play, visit ourBakken Companiespage.

DOC 3

Geology

The Bakken Formation comprises three distinct members. The upper and lower members are black, organic-rich shales and are widely recognized as world-class source rocks. These members also serve as very effective seals, owing to their very low permeability. Permeability ranges from 0.0120 mD. The middle member is the primary oil-producing member and predominantly composed of siltstones and sandstones but also has low porosity (1%-15%) and permeability (0-20 millidarcies),2particularly for a reservoir rock.

Because of the strong contrast in lithology, the Bakken Formation is readily recognizable in wireline logs. The upper and lower shales have unusually high gamma ray readings and high resistivity, while the middle member has a signature similar to clastic and carbonate rocks.2

Click to enlargeThickness

Current oil production activity has focused on the middle member as well as the underlying Three Forks Formation. The thickest area of the Bakken Formation is southeast of Tioga, North Dakota, T. 155N., R. 94W., Section 15, where it reaches 145150 feet. This area is located at the eastern base of the Nesson Anticline. The formation generally thins evenly toward the margins of the Williston Basin. The middle and lower members of the Bakken share a similar isopachoustrend(maximum thickness 75 and 55 feet, respectively); however, the upper shale demonstrates distributed areas of maximum thickness near the eastern and southern marginal shelf in North Dakota, in addition to maximum thickness near Tioga.

The overlying Lodgepole Formation consists of dense limestone and calcareous shale with minor amounts of chert and anhydrite, with a maximum thickness of 900 feet in eastern McKenzie, North Dakota. The Bakken is underlain by the Three Forks Formation, which has a maximum thickness of 250 feet in eastern McKenzie County. The Three Forks Formation consists of shales, dolostones, siltstones, sandstones, and minor occurrences of anhydrite.

Porosity/Permeability

Porosity and permeability within the middle member are generally very low. Porosity averages 5%, while permeability averages 0.04 millidarcies (MD). Porosity is influenced by burial depth, cement dissolution, and oil emplacement. However, the highest values are associated with naturally occurring hydraulic fractures. Higher values of permeability are also associated with natural fractures and contain higher volumes of residual oil.

Although total organic carbon levels may reach 7% in some of the shale interbeds, the organic content of the middle member is generally very low; it serves as a trap for oil derived from the upper and lower members, generally resulting in overpressurized conditions.2Depositional Environments

The late Devonian Period ended with deposition of shallow marine to terrestrial sediments of the Three Forks Formation as marine regression occurred to the northwest portion of the Williston Basin. Major uplift and erosion occurred along the margins of the basin sometime during the transition from the Devonian to the Mississippian Period. The sea likely withdrew to the area covered by the lower Bakken Shale, and various transgressions of the sea occurred throughout the time of Bakken deposition. The Bakken Shale indicates a change from highly oxidizing conditions during Three Forks time to highly anoxic conditions in lower Bakken time. The anoxic conditions continued until middle Bakken time as an influx of coarser clastics into the basin occurred. The middle member has fauna and bedding features indicative of a normal shallow marine depositional environment. Similarly, the upper shale indicates anoxic conditions followed by oxygenated water conditions during the Lodgepole time.

Interpretation of depositional environments of the upper and lower Bakken Shale has varied significantly over time. Currently, the most widely accepted model is a deep marine setting with a stratified water column.5This model is preferred because of the presence of pyrite, high concentrations of organic matter (derived from marine algae),6and a few benthic fossils. The clastic middle member is generally interpreted as a dramatic drop in sea level associated with a sediment influx. High-energy, near-shore tidal basins and lower shoreface depositional regimes are all represented in the middle member.2

Analog

There is no modern analog for the Bakken. The closest analogs are the Black Sea (which is no longer producing black shales) and the Arafura Sea (which also does not contain black mud) between Australia and New Guinea.7These basins are both poor analogs, as the Black Sea exists in a different depositional and geomorphic regime than that of the Bakken and the Arafura Sea (which vaguely resembles Bakken deposition) remains underresearched. The absence of a modern analog makes construction of a depositional model difficult which, in turn, makes reservoir facies models more difficult to construct and accurately apply.

Lithology

Click to enlargeThe upper and lower Bakken members are similar in that they are hard, siliceous, pyritic, fissile, brownish black to dark black, often noncalcareous, and organic-rich shales.3The shales are very uniform throughout their extents; however, some cores of the lower shale have thin (3 feet) black limestone that is coarsely crystalline and significantly lower in organic content.

Middle Member

The middle members lithology is highly variable and consists of five distinct lithofacies. The unit is well-sorted (although bioturbation is common); well-cemented with calcite, dolomite, or silica; and light to medium gray in color. All lithologies within the middle member have low primary permeability and porosity.

Middle Member Lithofacies4

Lithofacies 5 SILTSTONE, massive, dense, mottled, dolomite, argillaceous, tan to light gray, fossiliferous, disseminated pyrite, slightly bioturbated; contact with upper member is sharp. Cross-ripple laminations, as much as 6 inches thick, occur lower in half of section (occasionally fossiliferous).Lithiofacies 5 (PDF, 47 MB)

Lithofacies 4 LOWER ARGILACEOUS PACKSTONE TO FINE-GRAINED SANDSTONE AND UPPER INTERBEDS OF DARK GRAY SHALE AND BUFF SILTY SANDSTONE. Lower portion is medium gray, very fine-grained, dolomite cement, with thin parallel laminations. Upper portion is thinly laminated to cross-bedded siltstones and very fine grained sandstones, with moderately bioturbated, vertical burrows. Dolomitic cement in upper and lower portions with some dewatering structures.Lithiofacies 4 (PDF, 37.8 MB)

Lithofacies 3 DARK GRAY, FINE-GRAINED SANDSTONE TO MEDIUM-GRAY LIMESTONE. Sandstone is mainly quartzose with minor feldspar and heavy minerals, buff to green, moderately well sorted to well-sorted, rounded to well-rounded, contains calcite cement with occasional pyritic cement, disseminated pyrite, few brachiopods, and slight to no bioturbation. Limestone occurs along the southwestern extent and ranges from sandalgal packstone, to ooid packstone, to an ooidcrinoid packstonegrainstone. Oil staining may be present in the very fine grained, laminated, predominantly quartz sandstone portion.Lithiofacies 3 (PDF, 47 MB)

Lithofacies 2 GREENISH GRAY ARGILLACEOUS SILTSTONE TO BROWNISH GRAY SILTY SANDSTONE. Siltstone is moderately to very strongly bioturbated (disrupting the laminae), fossiliferous, dolomitic becoming calcareous with depth, and disseminated pyrite. Sandstone accumulations are restricted to localized highs.Lithiofacies 2 (PDF, 66.9 MB)

Lithofacies 1 ARGILLACEOUS SILTSTONE, massive, dense, mottled, very calcareous, gray-green, highly fossiliferous, with disseminated pyrite. The lower contact may be either gradational or erosive.Lithiofacies 1 (PDF, 41.7 MB)

Lithiofacies Central Basin Facies (CBF) (PDF, 54.7 MB)Oil Production

According to the U.S. GeologicalSurvey(USGS), the Bakken Formation is the largest continuous oil resource in the lower 48 states. Although the Bakken Formation is productive in numerous reservoirs throughout Montana and North Dakota, the Elm Coulee Field in Montana and the Mountrail County area of North Dakota were the first to benefit from modern, successful practices.15Bakken Formation Resource Estimates

Click to enlargeThe amount of oil in place (OIP, or total oil generated) in the Bakken Formation has been debated for decades. The estimates range from 10 to 500 billion barrels (Bbbl) of oil. The use of different methodologies is the greatest contributor to this extreme variation, along with data usage and available technology.

The first estimate, numbering approximately 10 Bbbl, was developed by Wallace Dow in 1974.8Data at that time were limited, and this was the first publication to suggest the Bakken Formation was capable of generating very large volumes of oil. Academic studies followed in the early 1980s, and the number increased to 92 Bbbl3and then 132 Bbbl9by 1983. The availability of additional data largely influenced these results.

The largest (and most controversial) estimate was developed by USGS geochemist Dr. Leigh Price in 1999.10Price's manuscript was never formally published as he passed away before the paper completed the review process. Price estimated total oil in the Bakken to range from 271 to 503 Bbbl, with an average of 413 Bbbl. His study was based on the largest data set available at the time and incorporated methods that accounted for changes in the rock units over geologic time.

Using a smaller data set and a new computer modeling package, Meissner and Banks11estimated 32 Bbbl of oil had been generated in the Bakken. Flannery and Kraus12used a more sophisticated modeling program and a much larger data set to develop a much larger estimate of 300 Bbbl.

Based on an independent evaluation, the North Dakota GeologicalSurvey(NDGS) currently believes approximately 167 Bbbl of oil that has been generated in the North Dakota portion of the Bakken Formation.13This estimate is in line with the large estimates by Price and Flannery and Kraus.

Of that 167 Bbbl of oil, the NDGS estimates approximately 2.1 Bbbl is technically recoverable with early 2008 technology.13At about the same time and using different methods, USGS released an estimate stating approximately 3.65 Bbbl is technically recoverable from the U.S. portion (North Dakota and Montana) of the Bakken using 2008 technology. These numbers are also roughly in agreement and represent only 1%2% of the oil that may be trapped in the formation.

Oil Recovery Well per Well

North Dakota Historical Monthly Oil Production

Click to enlargeOn an individual well basis, ultimate recovery from North Dakota wells ranges from 500,000 to 900,000 bbl per well, compared to 100,000 to 400,000 bbl per well in the Elm Coulee Field of Montana. Improved hydraulic fracturing technology including more fracturing stages has become a significant contributor to improved production. In addition, the productive reservoir section on the North Dakota side of the Williston Basin is thicker and more widely distributed, typical of an unconventional resource play. If the predictions prove to be accurate and are repeatable over a wide area, the Bakken would likely be the most prolific onshore oil play in the United States.

Completion

Click to enlargeCompletion and stimulation technology refer to hardware and methods used to construct wells and improve the fluid production after the physical construction of the well is completed. Completions are described by well design; orientation; areal spacing; and hardware, including liners, casing, methods of diversion, perforating, and cementing. Stimulation technologies include hardware and methods used to pump fluids and materials into the formation to increase contact with the reservoir to improve the rate and recovery of fluids from the formation into the wellbore and, ultimately, to the surface.

The North Dakota play is thicker and more widely distributed than the Montana play, allowing for more expansive development. Although horizontal laterals as long as 2 miles have been drilled, data suggest that these wells are only marginally more successful than wells completed at half the length.

The majority of wells in most Bakken producing fields utilize multistage fracture treatments. Some operators are attempting over 30 treatment stages within a 10,000-foot lateral. Most wells typically comprise asinglelateral completed in the upper Middle Bakken and utilize sliding-sleeve ball-drop systems for openhole multistage (OHMS) stimulation. Alternatively, plug-and-perforate technology has been used in cemented liners and can be used in addition to OHMS to increase multistage fracturing beyond the stage limits of sliding sleeves. Early in the play, some operators chose less costly completion methods that included single-stage fracturing of the entire horizontal wellbore. Although economical, generally, these wells were not as productive as multistage fractured wells.

Completion TechnologiesStimulation

Stimulation, or hydraulic fracturing, is a process used by oil and gas companies to increase production from wells that would otherwise have low production rates and low overall production totals. Hydraulic fracturing involves using a pressurized slurry of a fluid, typically water with a solid material referred to as proppant, to fracture or create cracks in the rock emanating from the borehole. This increases the effective conductivity of fluids within the formation and improves the connectivity of the formation to the borehole, allowing improved production of reservoir fluids, including oil or gas.

Stimulation Technologies

Stimulation relative to the Bakken Formation refers primarily to the hydraulic fracturing process of the horizontal wellbore. Hydraulic fracturing is performed to create greater conductivity of fluids within the formation and improved communication with the reservoir and the wellbore. The components of hydraulic fracturing include the hydraulic fluids and the proppants used to keep fractures within the rock open. Fracturing fluids are designed to inhibit corrosion, minimize bacteria growth, carry proppants into the induced fractures, and minimize reactivity with the formation. Generally, the fluids comprise water and dilute chemicals to provide improved properties. Proppants include sand and ceramics of specific sizes, strengths, and treatments that increase the likelihood for the proppant to remain in the formation versus flowing back to the surface with the fluids.

Hydraulic Fracture Stimulation Treatments

The size and type of hydraulic fracture treatments utilized in the Bakken Formation of North Dakota have varied over time. An example of a hydraulic fracture treatment for one operator in 2008 included the use of 950,000 gallons of fluid to place 1.9 million lb of proppant in a 5000-foot horizontal well. An example of a well in 2010 with a horizontal length of 10,000 feet used approximately 3.5 million gallons of fluid to place 4.5 million lb of proppant. Hydraulic fracture treatments can be pumped as asinglestage where the entire horizontal wellbore is fractured at one time or in multiple stages. Multiple-stage completion methods such as sliding-sleeve systems are typically employed first at the toe of the well treating a 250- to 500-foot zone isolated by packers and working toward the heel of the well. Modern technology allows the sequential multistage treatments to be conducted without the interruption of running tools into the well and decreasing treatment times to as little as 24 to 48 hours. The number of fracture stimulation stages in a Bakken or Three Forks well has increased to 40 stages in 2011 with the size of the job. Treatment costs vary, however. Stimulation treatments typically cost more than $2 million.

Fracturing Fluids

The selection of fracturing fluid is largely based on personal experience, geographic considerations, and advice from service providers. Generally, treatments in the Bakken have used water-based fluids. Fracturing fluids are required to be viscous enough to create a fracture of adequate width, maximize fluid travel distance to extend fracture length, transport large amounts of proppant into the fracture, and utilize gelling agents that break down to allow flowback of fluid and reduce flowback of proppant.

Additives to the fracturing fluids are used in a numbers of ways. The figure below lists potential additives and shows the general concentration of additives relative to the total volume of fluid. Fluid additives function to clean up the formation, prevent leakoff, and reduce surface tension. The additives include biocides, fluid-loss agents, enzyme breakers, acid breakers, oxidizing breakers, friction reducers, and surfactants. Primary categories for fracturing fluids include the following:

Gelled fluids linear or cross-linked gels

Foamed gels

Water and potassium chloride

Combinations of the above

Descriptions of fracturing fluids and corresponding additives are as follows. Linear gels include agents known as guar or cellulose derivatives that are biodegradable. The substances are polymeric, which thicken the water for better proppant transport. Guar gum is nontoxic and is a food-grade product commonly used to increase the viscosity of foods such as ice cream. Cross-linked gels are an improvement to linear gels providing greater proppant transport properties. Cross-linking reduces the need for fluid thickener and extends the viscous life of the fluid indefinitely. Metal ions such as chromium, aluminum, and titanium are used to achieve the cross-linking. Cross-linked fluids require breaking agents to reduce the viscosity for flowback. Breakers are additives of acids, oxidizers, or enzymes. Foamed gels use bubbles of nitrogen or carbon dioxide to transport proppant into fractures. The inert gases can reduce the amount of fluid required for fracturing by up to 75%.14Potassium chloride is sometimes used as a thickening agent for water-based fracturing fluids. Polymers in hydraulic fracturing fluids can provide a medium for bacterial growth. The bacteria can secrete enzymes that break down gels and reduce viscosity, which translates to poor proppant placement. Biocides are added to inhibit microbial action. Leakoff is the action of fracturing fluids emanating from the fracture into the rock matrix in which a fracture does not exist. Leakoff is controlled by adding bridging materials such as 100-mesh sand, soluble resin, or other plastering materials. Pumping of stimulation fluids can occur at maximum rates in which friction from high-viscosity fluids requires significant horsepower. Friction reducer additives are used to minimize energy requirements and primarily consist of latex polymers.

Proppants

A proppant is a hydraulic fracturing fluid additive that is used to hold the hydraulic fracture open and allow the flow of reservoir fluids. Proppants typically comprise sand or manufactured ceramics such as bauxite. Proppants can be resin-coated to improve packing, which helps the proppant stay in place and not flow back to the wellbore. Resin coatings also help provide better distribution of stress over the proppant pack. Proppants are specified in grain diameter sizes of less than 1/16 of an inch. Some common mesh sizes are 16/20, 20/40, 30/50, 40/70, and 100. Treatments may use one size or a multitude of sizes during pumping. The smaller sizes are intended to reach closer to the fracture tip. A propped hydraulic fracture has a significantly greater fluid (hydraulic) conductivity than the surrounding lower permeability rock matrix. Challenges to stimulation treatments involve proper placement of proppant, prevention of crushing or embedment, plugging at restrictions, and potential flowback of proppant to the wellbore.

Completion Technologies

There is significant variability in the well completions across the Williston Basin. Generally, the characteristics can be summarized as follows. The majority of wells are completed on 640- or 1280-acre spacing, resulting in 5000- and 10,000-ft horizontal wellbores, respectively. Operators that have already developed fields are now conducting in-fill programs, drilling as many as three wells within a given spacing unit in the Bakken and Three Forks Formations. Most wells are positioned in a north-south or northwest-southeast orientation to either take advantage of induced fracture propagation in the direction of maximum horizontal stress or to simply protect lease lines allowing for in-fill spacing or potential patterning for secondary/tertiary recovery projects. In all cases, wells are lined with casing from the surface to the base of the curve in accordance with state and federal regulations and to ensure the formation remains isolated from fluids in overlying formations. Operators have appeared to settle onsinglelateral completions in North Dakota. However, many variations of multilateral completions and orientations have been attempted. The lateral completions vary and are described below, including cemented liners, openhole completions, and noncemented liners with and without positive annular isolation.

Click to enlargeCemented linercompletions involve cementing the liner throughout the horizontal wellbore, allowing control of wellbore stability, direct control of fracture initiation, and greater well serviceability. Drawbacks include the potential for formation damage during completion and the potential isolation of natural fractures that would otherwise contribute to conductivity in the openhole. Commonly, the plug-and-perf stimulation technique is employed in wells with cemented liners. Plug-and-perf includes pumping down a bridge plug on wireline with perforating guns to a given horizontal location near the toe of the well. The plug is set, and the zone is perforated. The tools are then removed from the well, and the fracture stimulation treatment is pumped in. The set plug or ball-activated plug then diverts fracture fluids through the perforations into the formation. The stage is completed, the next plug and perforations are initiated, and the process is repeated moving back to the heel of the well. Cemented liners can also be used in single-stage fracturing operations, although they are less common in current Bakken completion practices.

Click to enlargeOpenhole completionis the most basic technique utilized in the Bakken. Early in the Bakken play, openhole completions were utilized for limited-entry fracture stimulation in which the entire lateral was treated in asinglefracture treatment. The method is relatively quick and inexpensive and has good potential for improved recovery from refracturing techniques. Single-stage fracturing in the openhole provides little control over fracture initiation and propagation. Other methods of openhole completions include the insertion of liners and ball-actuated sliding sleeve systems for multistage fracturing.

Click to enlargeUncemented, preperforated linerscan be inserted in the wellbore absent of annular isolation or with positive annular isolation. The objective of the preperforated liner without annular isolation is to provide a means to control fracture initiation and propagation by diverting fluids using perforation ball sealers, large-size proppant slugs, high-concentration proppant slugs, or fibers. The liner may be preperforated, at custom or regular intervals prior to emplacement, or perforated below the surface with an explosive device known as a perforation gun. The space between the liner and the wellbore (the annulus) is open, allowing formation fluids to freely migrate both inside and outside of the liner. The options for pumping the stimulation treatment inside preperforated liner vary and are frequently adjusted relative to the pressures and pumping history recorded during the job. Positive annular isolation of the liner provides for multistage fracture treatment methods described below.

Click to enlargePositive annular isolation of an uncemented lineris generally achieved with swell packers. The liner includes attached packers set at various intervals and designed to swell when introduced into the downhole environment to form a tight seal in the annular space of the wellbore. Both oil-based and water-based packers are available and matched with other downhole conditions such as temperature. Time is required to allow the packers to swell, usually a matter of a few days. The system typically remains in the well. However, there may be instances where swell inhibitors are applied to accommodate the development schedule. Liners may be preperforated and can accommodate either multistage frac-sleeve systems or plug-and-perf stimulation technologies. Uncemented liners with swell packers are a popular completion option in North Dakota, particularly for wells with large numbers of fracture stages.

Mechanical isolatorsor ball-actuated sliding sleeves have been utilized extensively in Bakken completions. The systems can be run inside a liner or in the openhole. The system comprises ported sleeves installed between isolation packers on asingleliner string. Packers isolate the horizontal wellbore into stages. A ball dropped into the fluid and pumped down the string will seat in the mechanical sleeve. This action will open the sleeve exposing the ports and diverting the fluid to the formation, which creates a hydraulic fracture within the isolated zone. This system is operated by pumping progressively larger-sized balls and operating sleeves from the toe of the well to the heel. The well is cleaned out by flow back to the surface, which returns fluid and solid particles. The balls and ball seats can be drilled out with coiled tubing. The technology allows for a quick and efficient fracture stimulation operation by minimizing fluid use, limiting trips downhole, and streamlining the pumping operation. Challenges include the potential for limited insertion of the tool string and failure of balls and seats in the opening of the sliding sleeves.

Completions in the Bakken Formation

Since horizontal drilling became standard practice over the past two decades, all of these completion methods have been utilized in the Bakken. However, the uncemented, preperforated liner isolated with swell packers has become the most commonly employed method of completion in most Bakken wells because of its high degree of fracture control and long-term success rate.

Eagle Ford Shale Geology

TheEagle Ford Shaleis a Cretaceous sediment that was traditionally known as a source rock in South and East Texas. The formation is the source rock for the Austin Chalk oil and gas formation. Producers also drilled through the play for many years targeting the Edwards Limestone formation along the Edwards ReefTrend. It was not until the discovery of several other shale plays that operators began testing the true potential of the Eagle Ford Shale.The shale is more of acarbonatethan a shale, but shale is the hot term of the day. The formations carbonate content can be as high as 70%. The play is more shallow and the shale content increases in the northwest portions of the play. The high carbonate content and subsequently lower clay content make the Eagle Ford more brittle and easier to stimulate through hydraulic fracturing or fracking. In geological terms, the Eagle Ford dips toward the Gulf of Mexico.

The formation was first targeted byLewis Energyin 2002, but most givePetrohawk Energy(acquired byBHP)creditfor discovering the Eagle Ford play many are targeting today.

LegacyAustin Chalkproducing areas (e.g. Giddings Field) have not proven to be the best drilling targets for the Eagle Ford. One theory is the Eagle Ford Shale formation improves as you move south due to degradation of the Austin Chalks reservoir properties, which in turn means the play expelled less oil and retained more.

Pearsall Shale Formation

Maverick Basin Map | Click to Enlarge

ThePearsall Shaleis a gas bearing formation that garnered attention near the Texas-Mexico border in the Maverick Basin before Eagle Ford development truly kicked off. The Pearsall Shale is found below the Eagle Ford at depths of 7,000-12,000 ft, with a thickness of 600-900 ft. Several operators, including Anadarko, Chesapeake, and Newfield, all expect to develop the Pearsall over time (aka when gas prices are better). Exploration in the play will increase as natural gas prices rise to a level that warrants activity.

The play does have liquids potential east of the Maverick Basin. As of 2012, only a few wells had been drilled in the play outside of the Maverick Basin. Early results indicate there is potential that has largely been overlooked.

TXCO Resources, who later went bankrupt and sold its assets to Anadarko and Newfield, touted the potential of the Pearsall before Petrohawks Eagle Ford discovery in 2008. The excitement was short lived as TXCO didnt make it through the recession and the Eagle Fords liquids yields supported better economic returns in a low natural gas price environment.

Eaglebine Formation or Eaglebine Shale Geology

TheEaglebineisnt asinglegeological formation, but is the name used by operators to describe wells that target both the Woodbine and Eagle Ford formations in a single wellbore. TheWoodbine formationis best known as the prolific reservoir in the famous East Texas Oil Field. The Eaglebine is largely targeted at the northern extent of the Eagle Ford region (e.g. Gastar in Leon County, Chesapeake in East Texas).

Eagle Ford Shale Geologic Structure

Source: Chesapeake Energy

Eagle Ford Shale Depths and Isopach Map

The Eagle Ford Shale producing interval is found at depths between 4,000 and 14,000 feet. The shale is up to 400 feet thick in some areas, but averages 250 ft across the play. Generally, natural fracturing is not prominent. To date, the most prolific area for production occurs along the Edwards ReefTrend(Stuart City Reef Trend) and where it converges with the Sligo Reef Trend. Both geologic distinctions are also referred to as the Edwards Margin and Sligo Shelf Margin.

Source: Chesapeake Energy