Vision Exploration Logo 

Black Warrior Basin

MAFLA* Formation
James Lime
Cotton Valley

*MAFLA - Mississippi,

Alabama & Florida

(Also Applicable to

East Louisiana)




TMS Interval


Richland Sand Interval


Richland Sand Mudlog


Laminated Oil

Sand Lens in TMS





Shell Fragments

Fissile TMS Interval




Fossiliferous Marl -

Basal TMS

"Bain" Interval



In TMS Core



Contact Us




The oil-prone Tuscaloosa Marine Shale (“TMS”) Trend occupies an oval-shaped area that straddles the Southwest Mississippi – East Louisiana (“Florida Parishes”) area (to view a map of the Trend, please click here). To date, the Eastern "Core" Area (consisting of the Southwest Mississippi and Florida Parishes area) has proven to be the most commercially important Trend area, with producing wells having been completed in the TMS at a true vertical depth ranging approximately from 11,000 feet to 14,000 feet subsea.  The Trend area is predominantly rural, consisting of farmland and pastureland, with some softwood timber cultivation.  Severance tax abatements, designed as temporary incentives, exist for horizontal TMS completions in both Mississippi and Louisiana.

Historically, the geopressured TMS was first encountered in September 1950, when Humble Oil & Refining Company encountered a strong influx of oil and gas from the Marine Shale of the Middle Tuscaloosa while drilling at a depth of 11,646 feet in a Lower Tuscaloosa test well in the southwest Gillsburg area (#1 Stockard, 33-1N-6E) of Amite County, Mississippi, just north of the state line.  The Gillsburg structure is a rare anticlinal closure in the Eastern "Core" Area of the TMS Trend.  Humble set intermediate casing, changed over to oil-based mud, and cored the remainder of the TMS in the #1 Stockard before drilling the well to a total depth of 12,500 feet.  The operator then plugged back to 12,052 feet and drillstem-tested an interval that included the lower portion of the TMS as well as the Lower Tuscaloosa.  The well flowed "by heads" on DST, yielding about 19 barrels of light green oil (from the TMS) and considerable saltwater (from an underlying Lower Tuscaloosa sand).  The well was abandoned, but the #1 Stockard became historically important as the first penetration of the geopressured TMS in what would later become known as the Eastern "Core" Area.  From that point forward, as the (conventional) Lower Tuscaloosa Trend expanded into Southwest Mississippi, the TMS became a tempting exploration target for some companies (Sun, Callon) and an annoyance and potential drilling hazard for everyone else.  Unfortunately for the optimists who attempted to test the interval, the few vertical completions in the TMS that were attempted over the years failed to extract more than a few barrels of oil on a daily basis, and interest in the TMS as a commercial oil resource waned.

The advent of horizontal drilling led several operators to drill short laterals into the TMS in the late 1990's, but those early laterals were not fracture-stimulated and soon declined to rates that were essentially the same as the vertical TMS completions attempted decades before (for reasons discussed further below).  In the late 2000's, attempts by Encore Operating to drill "longer" (2,000' - 3,000') laterals and to frac the TMS with single-stage stimulations were somewhat encouraging, but short-lived and plagued with completion problems. The first "modern" TMS lateral successfully drilled and completed with multi-stage frac technology was the Encana Weyerhaeuser 73H-1 well, drilled in North Chipola Field in St. Helena Parish, Louisiana in the fall of 2011.  The 73H-1 lateral, drilled after a pilot hole had cored much of the TMS, bottomed at a measured depth of 18,164' (TVD 12,662') in sidetracked hole after drilling a 6,117' lateral in the lower TMS.  Following a 17-stage frac that utilized 4,255,040 lbs. of proppant, the 73H-1 well officially reported an initial potential of 280 BOPD + 98 MCFGPD.  However, in its first full month of production (December 2011), the well produced 18,036 BO and 7,445 MCFG, a daily rate of approximately 600 BOPD + 248 MCFGPD.  This more impressive sustained monthly production rate, along with high oil prices, ignited the TMS Trend, which remained quite active until the downturn in oil prices began in the fall of 2014.  Drilling activity in the Trend essentially ceased by the summer of 2015 and all of the original TMS operators left the Trend by the end of 2016.  Encana, the dominant TMS player, eventually sold its holdings to Australis TMS, which drilled six new TMS laterals during 2018-2019.  By the winter of 2019, the Trend had once again grown quiet.

Here are some highlights from the recent drilling of laterals within the TMS Trend:

First TMS lateral drilled - Louisiana:   UPRC #5-1 Richland Plantation (STH #2) (East Feliciana Parish, Louisiana) (1998)

First TMS lateral drilled - Mississippi:   Worldwide Cos. #1 Braswell 24-12 (Pike County, Mississippi) (1998)

Longest lateral drilled to date:   Encana Lawson 25-13 H-1 (Amite County, Mississippi),   9,798 feet

Highest number of stages fractured:   Encana Anderson 17H #3 (Amite County, Mississippi),   32 stages

Largest total proppant load pumped:   Encana Lawson 25-13 H-1 (Amite County, Mississippi),   23,517,130 lbs.

Highest reported 24-hour Initial Potential ("IP24"):   Encana Longleaf 29H #2 (Amite County, Mississippi),   1,905 BOEPD

Highest reported 30-day Initial Potential ("IP30"):   Encana Longleaf 29H #2 (Amite County, Mississippi),   38,672 BOEPD, Average 1,289 BOEPD

Highest Cumulative Production as of October 2019*:   Encana Longleaf 29H #2 (Amite County, Mississippi):   538,877 BO + 164,656 BW + 227,848 MCFG (576,852 BOE in 57 months (93.4% oil); as of November 2019*, the 29H #2 was still producing at the rate of ~202 BOEPD)

Other wells of note: the Encana Lawson 25-13 H-1 (Amite County, Mississippi) has produced 465,342 BO + 323,840 BW + 147,934 MCFG (489,998 BOE in 57 months; as of November 2019*, the 25-13 H-1 was still producing at the rate of ~111 BOEPD); the Encana Mathis 29-17H (Amite County, Mississippi) has produced 349,010 BO + 232,338 BW + 166,149 MCFG (376,702 BOE in 58 months; as of November 2019*, the 29-17H was still producing at the rate of ~57 BOEPD); and the Encana Mcintosh 15-H #1 (Amite County, Mississippi) has produced 313,229 BO + 327,180 BW + 283,329 MCFG (360,451 BOE in 56 months; as of November 2019*, the 15-H #1 was still producing at the rate of ~61 BOEPD).

*Latest production reported to the State as of January 2019

A majority of TMS laterals drilled to date have been drilled "toe up", i.e, in an updip direction, sub-parallel to structural dip (which is generally south-southwest).  The advantage of drilling "toe up" is that one can take advantage of gravity drainage to aid in the production of oil from the lateral, especially later in its productive life.  Unfortunately, the logic of drilling "toe up" wells is compromised when a TMS operator lands its laterals in the lowermost portion of the TMS (as will be discussed later in this report), and fractures downward into the saltwater-bearing sandstones of the Lower Tuscaloosa.  When that occurs, extraneous saltwater collects in the "heel" of the lateral, severely impacting producibility and increasing operating cost. 

The TMS is a grey-black, moderately calcareous, kerogen-rich, microfractured marine shale with primary porosity ranging from 2% to 4% and average permeability less than .02 millidarcies (see the slabbed core photograph, left).  Commonly interspersed within the shale are numerous thin to wafer-thin sandstones, siltstones, and occasionally dolomitic marls.  These interlaminated siliciclastic zones are usually intensely cross-bedded and fractured, and in certain areas, can develop into thicker and more coarse-grained, glauconitic clastic lenses with significantly higher porosities (as high as 8%).  Analysis of the shale lithology indicates a general composition of 15–20% quartz and 40–50% clay with minor amounts of calcite, chlorite, feldspar and pyrite.

At the base of the TMS lies a highly bioturbated, more calcareous and fossiliferous unit that is informally labeled the “Bain” or “Pilot Lime” interval (see the slabbed core photograph at lower left).  The Bain interval, typically 25-30 feet in thickness, becomes more calcareous downdip, but even in the Southwest Mississippi area it is very hard with compressive strength that is much higher (300% more) than the more fissile, overlying TMS interval.  This is advantageous because the Bain interval can serve as a confining zone that limits the downward propagation of frac energy.  This in turn maximizes the fracture stimulation of the overlying fissile TMS, while minimizing the possibility of fracturing unintentionally into an underlying saltwater-bearing Lower Tuscaloosa sandstone.

At the very top of the Bain interval lies the Richland Sand, a thin sandstone deposited over a substantial part of the Eastern "Core" Area.  The Richland Sand is typically 4-8 feet thick and poor in porosity and permeability (see the slabbed core photograph at left, or click here to view a larger core image).  However, in certain key areas, it is clear that the Richland Sand harbors appreciable porosity and permeability and is saturated with oil and gas (click here to view a mudlog example).  In those key areas, the Richland Sand serves as a key "storage" component of the TMS, and in unconventional oil trends like the TMS, storage is key to commercial oil production (organic tracers have confirmed the contribution of oil from the Richland Sand in recently-drilled TMS laterals, and several wells have encountered porous, unconsolidated sand in cuttings from the Richland Sand interval; to view an example, click here).  The Richland Sand cannot be detected using the spontaneous potential (SP) curve, because it presents no SP contrast with the surrounding marls and shale.  However, the Richland Sand is readily mapped using the gamma ray curve.  Cores and gamma ray logs indicate the TMS contains several clastic fairways that harbor most of the primary porosity storage developed within the interval.  The deposition of the Richland Sand appears to be associated with a regressive pulse of clastics that heralded the end of the Bain depositional sequence; some have suggested that the Richland Sand is a hypopycnal plume deposit, which is an intriguing hypothesis.  There appears to be two updip sources of the clastics deposited within the TMS: a northeast Appalachian source, and a northwest Mississippi Embayment Source.  While most of the Eastern "Core" Area appears to have been sourced by the Appalachians, the Embayment source appears to furnish the clastics encountered in the area proximal to the Mississippi River.  In general, the updip Eastern "Core" Area is more clastic-rich than the downdip, more distal Florida Parishes area (to view a slabbed core example from the clastic-rich updip area, click here; to view a slabbed core example from the clastic-poor downdip area, click here; and to visually compare both examples simultaneously, click here.)

The highly resistive TMS facies thins laterally from a maximum thickness in excess of 200 feet (in the Eastern "Core" Area) to less than 30 feet of thickness in the west-central Louisiana area.  A similar loss of highly resistive shale occurs to the north and east as shown on the TMS Trend Map.  To the south, structural dip steepens south of the Lower Cretaceous (Edwards) Shelf, and the TMS plunges to depths deeper than 17,000 feet before becoming downthrown south of the first large down-to-the coast faults that cut the interval in the Baton Rouge area. Deep Lower Tuscaloosa wells drilled in that area confirm the transition of the TMS hydrocarbon “windows” from oil to dry gas, with a narrow wet gas (condensate) window interpreted in the deeper southern portions of the Florida Parishes, just north of the Deep Lower Tuscaloosa Trend. The Tuscaloosa Formation represents a complete depositional cycle of marine regression and transgression.  Prior to the deposition of the basal Lower Tuscaloosa, sea level fell and the entire Gulf Coast was extensively eroded.  The erosional surface at the base of the Lower Tuscaloosa represents the major unconformity that demarcates the Upper Cretaceous / Lower Cretaceous boundary.  For more information regarding the Lower Tuscaloosa, please click here.

In certain areas, it has been observed that a strong influx of oil and gas occurs high above the "traditional" top of the TMS.  The onset of this influx (gas kicks, oil “on the pits”) tended to be associated with the initial drilling of one or more basal Upper Tuscaloosa sandstones encountered approximately 150-200 feet above the top of the high-resistive TMS.  In some instances the strength and quality of the oil and gas show across the basal Upper Tuscaloosa (nicknamed the "EagleTusc" by this geologist) was much more intense than that of the underlying TMS.

The high-resistivity, "traditional" TMS is directly overlain by the marine shales, silts and sandstones of the basal Upper Tuscaloosa (EagelTusc) Formation, which is the time-stratigraphic equivalent of the Middle Eagle Ford in Texas.  While the marine shales of the EagleTusc are somewhat less calcareous than their underlying TMS counterparts, the interval is still brittle and easily fractured, and the clastic content is generally much greater.  It is clear that, because of its proximity to the TMS, in those areas where the EagleTusc is heavily fractured, its sandstones and siltstones have become highly charged with TMS-sourced oil and gas, at equivalent (abnormally high) pressures; and the combined interval is both fracture and pressure-interconnected.  The EagleTusc clastic units thus contribute substantial additional hydrocarbon “storage” capacity to the combined TMS / EagleTusc interval, which doubles in gross thickness when compared to just the highly-resistive TMS interval. Log analysis indicates that EagleTusc clastics generally average 4% to 9% porosity, exhibit moderately high e-log resistivity, and are highly laminated.  The thicker clastic units can exceed 40 feet in gross thickness and are easily correlated across the subject area, implying significant reservoir volume.  It appears that those EagleTusc intervals that exhibit resistivities in excess of 2 ohm-meters contain high clastic concentrations and represent potential hydrocarbon reservoirs.  The principle of mechanical stratigraphy best describes the preferential fracturing of the EagleTusc clastics in such a depositional setting; to view a classic example of mechanical stratigraphy, please click here.

Many geologists consider the Texas Pacific #1 Winnie Blades (completed May 26, 1978; 42-1S-8E, northern Tangipahoa Parish, Louisiana) to be an important vertical legacy well for the TMS, in that it had reputedly produced oil from the "TMS" for several decades.  What most geologists do not realize is the #1 Blades was actually completed across a ~600' interval that was comprised of not only the "traditional" TMS interval, but also the overlying EagleTusc interval.  In fact, more intervals were perforated within the EagleTusc than in the "traditional" TMS in the #1 Winnie Blades "TMS" completion.  (This was because of the good mudlog oil and gas shows that had been observed across the subsequently-perforated EagleTusc intervals, well above the top of the "traditional" TMS.)  When Encana petitioned the Mississippi Oil & Gas Board for Special Field Rules for its TMS oil fields in Southwest Mississippi, it expanded the definition of the "TMS" to specifically include virtually all of the stratigraphic equivalent of the overlying EagleTusc.  To view the #1 Winnie Blades "Type Log", and the stratigraphic relationship of the TMS and overlying EagleTusc, click here.

Geopressure within the TMS is confined to open fractures and permeable clastic intervals.  Where the matrix is virtually 100% shale, the interval is impermeable, and the matrix of such shale is not geopressured.  The system of microfractures within much of the TMS (created by the cracking of oil to gas following generation) collapses within a radius around a TMS producing wellbore as hydrocarbons are removed (and pressure diminishes) via drilling or production. Mudlog shows are attributable to gas and oil liberated when a cylindrical volume of the microfractured TMS is drilled up by the bit.  In most cases, this influx diminishes significantly as the microfractures around wellbore are de-gassed and collapse.  Contrary to what has been claimed in the past, there are no verifiable instances of loss of control ("blowouts", etc.) attributable to the uncontrollable influx of oil and gas from the shale intervals within the TMS; virtually all such incidents are actually associated with the influx of geopressured hydrocarbons from clastic units within the overlying EagleTusc or developed at the very top of the TMS. 

For these reasons, vertical wells drilled through the TMS typically de-gas the shale around the wellbore within 12-24 hours of drilling the interval, which is usually less than 150 feet in thickness.  This permits drilling to continue with mudweights only slightly elevated above "normal".  Hundreds of (vertical) Lower Tuscaloosa wells have been successfully cored and logged after drilling and controlling the TMS with mudweights of less than 10 PPG.  However, a TMS lateral continues to drill (as intended) through the geopressured, fractured TMS interval over an interval that may exceed 9,000', and the mudweight typically required to control the lateral wellbore and keep it from collapsing is approximately 13 PPG.  The geopressure gradient within the TMS ranges from 0.50 psi/ft. in the northern (presumably non-commercial) part of the Trend to 0.75 psi/ft. in the downdip Florida Parishes area.  In the heart of the Eastern "Core" Area, the geopressure gradient within the TMS fracture systems averages 0.65 psi/ft (the "normal" Gulf Coast pressure gradient for saltwater (with 100,000 ppm total dissolved solids) is 0.465 psi/ft.).  The frac gradient for most of the frac stimulations in the Eastern "Core" Trend typically averages 0.95 psi/ft to 1.05 psi/ft.

An excellent example of the de-gassing of TMS microfractures  in a vertical TMS penetration is the post-drilling well flow test conducted in a TMS vertical wellbore drilled recently in eastern Wilkinson County, Mississippi.  This well is now surrounded by lateral TMS producers that required ~13 PPG mudweight to drill and control each lateral wellbore.  In the vertical TMS wellbore, after coring and logging operations had been completed, to determine the flow potential of the open TMS interval, the operator injected nitrogen into the mud system to temporarily lower the density of the drilling mud and thus lower the hydrostatic pressure in the wellbore to an equivalent ECD ("Equivalent Circulating Density") of only 7.8 PPG.  The well had been drilled underbalanced with oil-based mud, and there was no significant mud loss to the formation.  The influx of oil and gas from the TMS that had occurred during the drilling stage had virtually ceased by the time the nitrogen-cut well flow test was conducted, a few days later.  The microfracture system encountered by the wellbore had de-gassed and essentially collapsed around the wellbore.

The pervasive microfracturing of the TMS has been enhanced in certain areas by the drape of the TMS over underlying structures and regional flexures (dip/slope changes), which created sub-regional fracture swarms that augmented the microfracture system.  Fracture swarm orientation is generally “strike” (NW-SE) oriented, but may vary locally in such “enhanced fracture” areas.  Knowledge of the location and extent of these enhanced fracture areas, and clastics content and distribution, aids in targeting potential “sweet spots” in the Trend, where storage was optimal.  Click here to view an illustration of enhanced fracturing caused by differential compaction over the underlying Lower Tuscaloosa "A" Sand, when present; to view a similar illustration of enhanced fracturing caused by a dip/slope change or drape over a deep-seated structure (like the Gillsburg Structure), please click here.

Because the geopressured oil and gas that microfractured the shale is the only force holding the microfractures open, draining the oil and gas from those microfractures causes them to collapse, dramatically impacting the producibility of a TMS wellbore.  Injecting large volumes of proppant into the microfracture system obviously alleviates the problem in the vicinity of the stimulated area, but it is clear that the best production is going to be derived from areas where a frac’d TMS lateral accesses not only the microfracture system but also the larger sub-regional macrofracture swarms and the porous and permeable, oil-saturated clastic lenses within the TMS (that will not collapse when drained).  Already, certain TMS wells are clearly outperforming the average TMS decline curve, and this geologist believes those better wells have accessed nearby areas of enhanced storage - the much sought-after "sweet spots" in the Trend.

Relatively few TMS pilot (vertical) wells have been drilled by the companies that have recently drilled long lateral wells in the TMS.  This means that the most of the well data needed to understand the TMS Trend on as regional basis remains that contributed by the abundant "legacy" vertical wells drilled in the area, which principally targeted the underlying Lower Tuscaloosa Stringer Sands.  This geologist has worked the Lower Tuscaloosa Trend since 1981 and was a wellsite geologist responsible for coring and logging numerous Lower Tuscaloosa legacy wells in the Eastern "Core" Area.  In addition, Vision Exploration served as geological and land consultant for one of the most active companies exploring the TMS from 2011-2015; as such, Vision has had access to the well data associated with the majority of TMS laterals drilled in the Trend during that important period.  This combination of 36 years of Tuscaloosa / TMS Trend experience and access to the recent TMS well data clearly sets Vision apart from most independent consulting groups that claim to have experience in the Trend, which is important because much of the information that has been previously published about the TMS is - in this geologist's opinion - incomplete, misleading, or simply inaccurate.

For example, it has been claimed that the Passey Log Analysis Method can be accurately utilized to identify and calculate Total Organic Carbon ("TOC") in the legacy Lower Tuscaloosa penetrations within the TMS Trend, by overlaying the sonic transit time curve on the deep induction resistivity curve; hydrocarbon-bearing or organic-rich rocks could then be identified by observing those intervals where separation between the sonic and resistivity curves is observed.  The gamma-ray curve is also used as a discriminator, but the reliance upon the sonic curve as the key porosity curve is a critical and integral component of the Passey Method as employed in the log analysis of the legacy wells drilled within the "Eastern Core Area" of the TMS.

Unfortunately, regardless of whether one agrees with the efficacy of the Passey Method, one cannot utilize sonic curve data across an interval where the wellbore is washed out.  A washed-out ("rugose") wellbore cannot be accurately logged with a sonic tool.  This is a basic tenet of petrophysical analysis.  Virtually every legacy Lower Tuscaloosa wellbore drilled in the TMS Trend was severely washed out across the TMS interval when logged.  This was principally the consequence of (1) drilling the TMS with a high water-loss, water-based drilling fluid; (2) diamond coring operations frequently conducted just below the TMS (across the Lower Tuscaloosa "A" Sand), which were often lengthy and required considerable reaming of the hole both before and after such coring attempts; and (3) more reaming and hole conditioning that followed once the well had been drilled to total depth and the operator was prepared to log the well.

A sonic log run across a washed-out TMS interval will obviously yield an erroneous (slow) acoustic travel time, because the rugose hole is filled with drilling fluid, which is only a fraction of the density of the TMS matrix.  Such sonic travel times are worthless and should not be used in any petrophysical calculations, including the Passey Method.  For this reason, it is critically important that the caliper or differential caliper curve be presented (displayed) whenever porosity log curves - and especially sonic log curves - are presented.  If the caliper or differential caliper curve is not presented or not available, the use of the sonic curve should be automatically called into question, and until rugosity is ruled out, any resulting sonic log analysis must be invalidated.  To view an example of a legacy Lower Tuscaloosa wellbore drilled in the Eastern "Core" Area that was severely washed out across the TMS interval, click here.

Yet this geologist has witnessed numerous TMS "Passey" log analysis displays where the caliper or differential caliper curve was not presented.  In virtually every such presentation, this geologist has immediately recognized the sonic log that was used in the analysis to be invalid across the TMS because of severe hole rugosity. It is unfortunate that such data is presented as valid petrophysical data.  It is not.  With very rare exceptions, the only wellbores that are not washed out across most of the TMS interval are those wellbores that have been carefully drilled with oil-based mud (and only a few recently-drilled wells meet this criterion).  This geologist has observed the porosity logs run across the TMS in those few wells (most all of which were recently-drilled TMS "pilot" holes), and there is negligible Passey separation or correlation with TOC.  Accordingly, it appears that the Passey Method is neither a useful nor an accurate petrophysical method for analyzing vertical legacy wells drilled in the TMS Trend.  Many "Shale Oil Advisor" logs have also failed to correlate accurately with the lithology, clay minerology, and TOC obtained from cores cut across the TMS in the same wells; for example, this geologist has observed Shale Oil Advisor logs generated from wells drilled in the downdip distal Trend to indicate very sandy intervals within the TMS were penetrated, while the diamond cores cut across the same interval yielded virtually 100% shale with nil laminated sand or silt.  This suggests that much modeling work remains to be done before such "advisor" logs can be trusted to yield reliably accurate and correlative results in the absence of diamond cores.

The "traditional" TMS interval is commonly associated with increased resistivity in the Middle Tuscaloosa Marine Shale interval, and many geologists use an arbitrary resistivity cut-off of 4 ohm-meters in mapping the prospective area within the Trend.  Resistivity is a function of lithology (increased calcium content) within the TMS, and has nothing to do with the presence of hydrocarbons.  In fact, the most highly resistive intervals within the TMS are the least porous and permeable, and contain the lowest TOC.  The highest resistivity in the TMS Trend is associated with areas where the TMS lithology has transitioned to a marl or marly limestone (in the southern portion of the Trend).  While higher resistivity can be linked with harder, more brittle TMS facies, high resistivity cannot be quantitatively associated with the presence, volume, or recovery of hydrocarbons. Any attempt to directly associate the thickness of highly resistive TMS strata with hydrocarbon volume or recovery is fatally flawed.  The best utility of mapping TMS resistivity is for locating the thickest areas of brittle TMS rock; one must then attempt to associate the proximity of that highly-resistive, brittle rock to areas of optimal storage (enhanced fracture areas, porous clastics) developed within the Trend.

Inexplicably, even though the fissile, highly-prospective "traditional" TMS interval is typically over 130'-140' in thickness, many TMS operators have chosen to land their TMS laterals within the 30 foot-thick Bain interval located at the very base of the TMS, literally 15 feet or less from the base of the TMS.  The Bain interval is the most calcareous, hard, and brittle interval within the TMS.  It grades lithologically from a nonporous bioturbated marl in the Southwest Mississippi area to a relatively pure shallow marine limestone in the downdip southern Florida Parishes area of Louisiana, where it was nicknamed the "Pilot Lime" by geologists targeting the underlying Deep Lower Tuscaloosa Trend.  In much of the Eastern "Core" Area, the Bain can be further subdivided into three distinct units, each typically 10' thick: the Upper Bain, which includes the Richland Sand interval at the top of the unit; the Middle Bain, which is much more shaley, and contains the only appreciable TOC within the Bain interval; and the Lower Bain, which is the most calcareous, densest and least porous unit.  By conducting massive fracture stimulations of their laterals landed in the (preferably Middle) Bain interval, TMS operators have undoubtedly frac'd into the underlying saltwater-bearing sandstones of the Lower Tuscaloosa, which can be developed less than 30 feet below the base of the TMS (TMS frac half-heights for 400,000 lb. frac stages have been calculated as extending downward 200 feet or more).  Many TMS completions are only now manifesting the influx of large volumes of extraneous brine from the Lower Tuscaloosa.  An unfortunate example is the very first TMS well that was frac'd with a "modern" multi-stage stimulation, the Encana Weyerhaeuser 73H-1; this well has produced large volumes of extraneous brine, yet the proppant loads pumped away in its fracture stimulation were only half the size of average proppant loads pumped just two years later.  Because the underlying saltwater-bearing sandstones of the Lower Tuscaloosa are normally pressured, significant production of the extraneous Lower Tuscaloosa brine will not occur until the higher reservoir pressure of the TMS declines to an equivalent of the Lower Tuscaloosa pressure.  For this reason, serious issues with extraneous water production will typically not be manifested until the TMS lateral has been in production for approximately a year, if not longer.

The compressive strength of the Upper and Lower Bain intervals is 300% greater than that of the overlying fissile, microfractured, hydrocarbon-bearing TMS.  As is the case with many shales, the fissile TMS interval, which harbors >90% of all of the hydrocarbons trapped within the TMS, is horizontally / laterally weak (along the bedding planes), and proppant pumped into the fissile TMS will propagate much further laterally than proppant pumped into the non-fissile, much harder Bain interval.  Since the stated intent of TMS operators is to drill wells into the most productive intervals of the TMS, and to propagate as much proppant as possible into the targeted source rock, one would think that those operators would focus their drilling and completion efforts on the fissile, microfractured, hydrocarbon-bearing TMS.  But that is often not the case.

Some operators have described a "rubble zone" to exist within the lower fissile TMS, just above the Bain interval.  The implication is that there is an interval of rubble (loose rock) in the TMS. 
No such interval exists; this interval has been extensively cored and drilled, and is lithologically similar to the overlying fissile shale interval, but it (like the overlying fissile interval) is certainly more microfractured than the underlying Bain interval.  To view a core cut across the so-called "rubble zone" in a key TMS pilot hole (in the heart of the Eastern "Core" Trend), click here.  Ironically, the stated purpose of the drilling of unconventional, frac'd laterals is the rubblization of an otherwise "tight" source rock via the fracture stimulation of a microfractured interval.  Because of the geopressure, intervals of optimal fracturing (the important macrofracture swarms) within the TMS are more challenging to drill, but they are not to be avoided; they should be deliberately targeted by the bit.  Unfortunately, historical drilling data collected from 2011 to 2015 has demonstrated that many TMS operators still lack the expertise or willingness to drill such challenging intervals.  Casing deformation and parted casing has been blamed on the so-called rubble zone, but the reservoir is not the issue (recall that the shale of the TMS itself is not geopressured; the pressure is constrained to the open fractures and porous clastics).  What isn't routinely discussed is the fact that virtually all of the recent TMS laterals were drilled during "boom times" for the unconventional oil trends in the United States, and 36 years of experience with other "boom and bust" cycles has demonstrated to this geologist that mechanical issues attributable to substandard casing and inexperienced drilling and casing crews are very common during such "boom" times, and the principal cause of the vast majority of such mechanical failures - regardless of whether those failures occur onshore, or offshore.

The TMS Trend is one of the deepest and most challenging unconventional oil trends in the United States.  It remains poorly understood and, in the opinion of this geologist, suffers from the dissemination of considerable erroneous information regarding its lithology, prospective intervals, storage capacity, and producibility.  As this geologist had predicted in 2011, certain areas previously identified within the Eastern "Core" TMS Trend are now emerging as commercially important "sweet spots"; the identification and exploitation of these sweet spots will remain critically important as the current Trend production matures during a period of low commodity prices and minimal new drilling activity.

Steve Walkinshaw, President, Vision Exploration

This report is intended to comprise a brief geological summary of the TMS Trend, and reflects the technical observations and professional opinions of Vision Exploration, LLC; if your company is interested in the Trend, and you would like to learn more about the TMS, or wish to take advantage of our Trend experience and technical expertise, please feel free to contact us.

This entire site Copyright © 2020.  All rights reserved.