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parker and palo pinto plays:
Scattered, often poorly exposed, strata that can be correlated with the Upper Pennsylvanian Palo Pinto and Posidion formations (Lowery, 1962), Canyon Group, Brazos River Valley, occur in western Wise County, Texas. These northwest dipping rocks are unconformably overlain and often obscured by southeast dipping Lower Cretaceous (Comanche Series) sand and conglomerate. In the early 1900's, Bose, Plummer and Moore, and Scott and Armstrong proposed several names for these Pennsylvanian limestone strata (Bridgeport, Hudson Bridge, Martin Lake, Balsora, Sanders Bridge, Boone Creek, and Willow Point), mostly with brief descriptions and poorly located type sections.
Examination of exposures of these strata and their contained fusulinid and conodont faunas has demonstrated that (in descending order): (i) a conodont rich black mudstone (indicating maximum flooding) in the base of the Wolf Mountain Shale and just above the Wiles Limestone correlates to a similar interval just above the Willow Point Limestone, well exposed in the area around the south side of Lake Bridgeport; (ii) the Willow Point Limestone (= Bridgeport Limestone, no longer used) correlates to the Wiles Limestone (top of the Posideon Formation, Brazos River Valley); (iii) a conodont rich black mudstone present in the middle part of the Posideon Formation correlates to equivalent age strata in the Martin Lake area just south of Bridgeport; (iv) the Martin Lake (= Balsora) Limestone (fusulinid/algal grainstone indicating very shallow marine sediments) correlates with the top part of the Palo Pinto Formation; (v) the Sanders Bridge Limestone correlates with the middle part of the Palo Pinto Formation; (vi) the Hudson Bridge (= Boone Creek) Limestone correlates with the lower part of the Palo Pinto Formation.
Basin-Centered Tight Gas Sands and Thrust Faulting in Central Parker County of the Fort Worth Basin: Jimmy D. Thomas
The Fort Worth Basin formed during Early and Middle Pennsylvanian due to the oblique collision of the Afro-South American and North American plates. This tectonic activity not only affected deposition at that time but also affected the underlying formations. Depositional environments changed from shelf carbonates to shallow marine to deep marine then back to shallow marine during basin development. Eustatic cycles combined with tectonic activity have complicated mapping efforts and led to many misunderstandings about the basin. Much of the basin center is unexplored and has potential for enormous gas reserves. Reservoir mapping of just the basin-centered tight gas sediments indicate natural gas reserve potential in the tens of TCF. Is this another giant reservoir that can be "gas-farmed" much like the Barnett Shale?
A four-hundred-foot throw thrust fault extends through southern Parker County with open hole logs indicating repeat sections in the Barnett Shale, Atoka and Strawn formations. Due to the cyclicity of sediments during this time, most of these repeat sections can be mapped as separate deposits. It is also believed that due to the oblique collision of the plates, lateral fault movement and faults of different orientations complicate the understanding of tectonics during this time. This tectonic activity has the potential to have created additional "sweet spots" in the Barnett Shale similar to the Newark East gas field. Faulting and fracturing may have created potential permeability enhancement and hydrocarbon traps in the Ellenburger and Marble Falls making these formations exploration and development targets. Due to a lack of drilling, very little is known about these formations in most of the basin. The Fort Worth Basin is a new exploration frontier for combining the advances in geology and engineering technologies.
gas plays in the barnett shale:
Barnett Shale: A Significant Gas Resource in the Fort Worth Basin: Craig Adams
The Mississippian Barnett Shale of the Fort Worth Basin is an organic-rich shale that is the reservoir trap and seal for a very large unconventional gas accumulation. The play has rapidly spread over a multi-county area.
The Barnett Shale is a spent oil-prone source rock. Porosity and permeability is developed upon thermal transformation from liquid to gas with resulting maturation-induced micro fractures. Gas is stored in these micro fractures, as well as being adsorbed in the solid organic matter (kerogen). The exploration fairway is defined by Barnett Shale isopachs, subcrop maps, source rock richness data (Total Organic Carbon), thermal maturity defined by vitrinite reflectance and the presence of reservoir quality Barnett Shale.
The Barnett Shale is one of the most active drilling targets of the past decade. Newark East Field is now the second largest gas-producing field in Texas. Drilling depths are less than 8,000 ft, and per well reserves in the expanding Newark East Field are 1-3 BCF. Gas-in-place is 145 BCF per square mile. The Barnett Play is estimated to have 10 TCF recoverable reserves (USGS, 1998).
Low proppant hydraulic fracturing technology ("water-fracs") has greatly improved play economics. This new technology has reduced total well cost by more than 20 percent and has resulted in much-improved rate and reserve profiles. Barnett Shale wells are typically re-fraced after several years resulting in producing rates superior to initial production rates.
The Barnett Shale Play, Fort Worth Basin: Kent A. Bowker
In terms of monthly production, the Newark East (Barnett Shale) field recently became the largest gas field in Texas. Production has grown from 80 MMCF/D in January 2000 to over 560 MMCF/D at present because of accelerated new-well drilling and old-well reworks/refracs. There are over 2.5 TCF of booked proven gas reserves in the field at present. Newark East field is located in the northern portion of the Fort Worth Basin, just north of the city of Fort Worth. The Mississippian Barnett rests on an extensive angular unconformity. The Barnett must be stimulated to achieve economic flow rates. Currently, wells are hydraulically fractured, but good frac barriers must be present directly above and below the Barnett for this stimulation technique to be successful. Hence, the stratigraphy above and below the Barnett is important to economic production. The thermal history of the basin is an important reason for the success of the Barnett. The thermal history of the Fort Worth basin is directly related to the emplacement of the Ouachita system. Sections of the Barnett bordering the Ouachita front (regardless of depth) have the highest thermal maturity and, hence, the lowest BTU content of produced gas. In the late 1990s, work by Mitchell Energy had demonstrated the viability of water fracs in the Barnett play; this development has contributed to a huge acceleration in Barnett leasing and drilling activity during the past three years. Also in the late 1990s, Mitchell determined that the previous gas-in-place values for the Barnett were low by over a factor of three. There is approximately 150 BCF/mi2 of in-place gas in Newark East field. The realization that the primary completion was only recovering 7% of the gas in place per well spurred the current (and very successful) rework/refrac program underway in the field.
The history of the evolving geologic and engineering concepts that guided development of the Barnett is a tribute to rare perseverance in the oil patch. And the success of the Barnett play may provide a model for prospecting for other large shale-reservoirs.
Barnett Shale Gas-in-Place Volume Including Sorbed and Free Gas Volume: Matt Mavor
Gas contained within unconventional shale gas reservoirs is stored by sorption within micro and mesoporosity of the rock matrix and by compression within the macroporosity and natural fracture porosity of the reservoir. Mitchell Energy cored the Kathy Keel #3 Barnett Shale well (Denton Co. Texas) with conventional and pressure coring equipment in the upper and lower Barnett to obtain core samples and data to obtain data required to estimate the gas-in-place volume stored by each mechanism. An extensive suite of data was measured that included desorption of samples to determine the sorbed gas content and gas composition as well as methane and ethane sorption isotherm data to estimate the sorbed gas storage capacity.These data were combined with other shale gas core analyses including TOC content, routine porosity, grain and bulk density, water saturation, capillary pressure, x-ray diffraction, and cation exchange capacity data to develop a log analysis model that combined log and core analysis data.
The estimates of the gas-in-place volume were significantly greater than past data measured and published in 1992 by Gas Research Institute (GRI) had indicated. The volume of gas stored by sorption within the pressure core interval was 120 scf/ton at an average TOC content of 5.2% compared to GRI's estimate of roughly 42 scf/ton. The sorbed gas volume accounted for 61% of the total gas-in-place volume that included both sorbed and free gas. Free gas volume in-place was determined by log analyses methods that were calibrated to core analyses to obtain in-situ estimates of porosity and water saturation.
While the gas-in-place volume is large, recovery of the gas volume is hindered by relatively low absolute permeability of the reservoirs. Recovery of the sorbed gas-in-place requires that operating pressures be kept low as possible to allow the gas to be released from the sorbed state. Recovery factor depends upon the decline in average reservoir pressure. Calculation methods for gas recovery factor will be discussed to illustrate that recovery factor may range from 10 to 25% of the total gas-in-place volume with conventional technology.
Microseismic Mapping During Frac Stimulation in the Barnett Shale: Nick Steinsberger
The Barnett Shale in North Texas is one of many tight shale plays across the country, however, over the last two years the Newark East (Barnett Shale) field has been the most active field in the United States. With an average of 35 drilling rigs running in the Fort Worth Basin, over 2000 wells have been drilled in Wise, Denton, and Tarrant counties for the ultra tight gas. The Barnett Shale is present in most of North Texas and has been tested in more than 12 counties by more than 50 operators.
Determining Petrophysical Properties and Gas Content in the Barnett Shale Using a log-based Neural Network Solution: Lee Utley
The Barnett Shale in the Fort Worth Basin of Texas is an organic-rich black shale capable of producing large amounts of natural gas and natural gas liquids. Traditional log analysis methods have not yielded acceptable results when attempting to determine standard petrophysical properties. Therefore, log analysis alone is an impractical method of predicting production in the Barnett Shale. Production in the Barnett Shale is affected by several factors, only some of which may be measured or calculated using log data, making gas content a poor predictor of well performance. However, a neural network technique has been developed to successfully estimate reservoir potential that relies on log derived qualitative and quantitative parameters.
Log analysis in the complex lithology of the Barnett Shale is very difficult. The existence of several exotic minerals in the matrix along with significant amounts of organic material makes a algorithm-based solution virtually impossible. Using extensive core data, a neural network solution was developed to calibrate the logs to the needed petrophysical properties, and thus enable the foot-by-foot calculation of gas content of the Barnett Shale. Since any evaluation technique requires proper verification, examples will be shown to demonstrate the effectiveness of the calibration.
The logs required to perform the analysis are readily available on most wells in the Fort Worth Basin, making the solution a practical exploration/exploitation tool. Outputs from the analysis include porosity, total organic content, water saturation, lithology, and gas content, both in the sorbed and free states.
Newark East, Barnett Shale Field, Wise and Denton Counties, Texas; Barnett Shale Frac Gradient Variances: David Martineau
The Newark East, Barnett Shale Field is one of the largest producing gas fields in Texas. The initial development of the field was centered in the southeast quarter of Wise County, and, over the past 20 years the field has expanded to the north, west, to the east into Denton County and the the South in Tarrant County. With the development of the field came the increased knowledge of the nature of the reservoir, the frac gradients and the porosity zones, all of which was important in the economic development of the Barnett Shale play.
In the early development it was recognized that the Upper Barnett (+100') had a higher frac gradient (.70+) than the Lower Barnett (.50 to .60+) (+300'). As the field developed and expanded in aerial extent, it became apparent that in the north part of the field the Lower Barnett (+600') could be subdivided into five (5) ("A" thru "E") correlatable porosity units with limestones and non-bituminous calcareous shale separating the productive porosity units.
With further investigation and evaluation of the Lower Barnett it became apparent that the upper "A" and "B" porosity units could have a different frac gradient than the lower "C", "D" and "E" units in certain areas.
Even though the majority of the water frac treatments consist of two phases, one for Lower Barnett and another for Upper Barnett, certain areas of the field will require multi-stage fracs to adequately recover the true reserve potential of the Barnett Shale.
Production logs and radioactive tracer surveys have been used to evaluate the effectiveness of frac jobs covering 300' to 600' intervals, where each zone could have variances in frac gradient, fractures and/or porosities.
As the field continues to expand beyond the Viola/Ellenberger subcrop, additional new data will possibly dictate a change in frac procedure.
Assessing Undiscovered Resources of the Barnett-Paleozoic Total Petroleum System, Bend Arch-Fort Worth Basin Province: Richard M. Pollastro
Organic-rich, Barnett Shale (Mississippian) is the primary source rock for oil and gas produced from Paleozoic reservoirs in the Bend Arch-Fort Worth Basin Province. Distribution and geochemical typing of hydrocarbons in this mature petroleum province indicates generation and expulsion from the Barnett at a depocenter coincident with a paleoaxis of the Fort Worth Basin. Barnett-sourced hydrocarbons migrated westward into reservoirs of the Bend Arch and Eastern shelf; however, some oil and gas was possibly sourced by a composite Woodford-Barnett petroleum system of the Midland Basin from the west.
Current U.S. Geological assessments of undiscovered oil and gas are performed on Total Petroleum Systems (TPS) that include mature source rock, known accumulations, and area(s) of undiscovered hydrocarbon potential. The TPS is subdivided into Assessment Units based on similar geologic conditions and accumulation type. Assessment of the Barnett-Paleozoic TPS focuses particularly on the continuous Barnett accumulation. Barnett shale gas will be assessed after mapping "sweet spots" and outlying areas of potential, and by defining distributions of drainage (cell) size and cell estimated ultimate recovery. An example of a Barnett "sweet spot" is the Greater Newark East area where thick, siliceous Barnett has reached the gas window, and overlain and underlain by impermeable limestones that serve as "frac" barriers. Assessment Units are also identified for mature conventional plays in Paleozoic carbonate and clastic reservoirs, such as the Chappel Limestone pinnacle reefs and Bend Group conglomerate, respectively. However, Barnett continuous gas is expected to add the greatest volume of undiscovered, technically recoverable resource.
ctb, congrats on your new purchase and the fun you're going through. yesterday, i bought materials to install submersible sump pump and the pvc to go with it...got a depression where water pools and when we get hard rains lasting more than a few days. the days on pumping water out manually are numbered. i just to got start digging and all that stuff. i'm about ready to fire up a new gas grill that i got last year and try my hand at bbqing with the gas. been marinating the chicken with a brine all night long, hopefully it be good.
it is nice to read about geological aspect with some focus spent on it. let me see if i can add a bit here....
coach, can't post you back privately now. my answer... when we have numbers/updates! have a good weekend.
hey ctb, happy hour is over, lol. about ready to go shopping for some yard stuff and food. working in the yard and bbqing is the order of the weekend. what's shaking your way?
alan,
are you living in the uk? i usually hang out in oban and edinburgh with mates when i visit; done many a pub crawl.
great questions as i'm looking forward to bsd's reply, because as you have laid it out - that's the way i understand it (just didn't know the dome formation bit).
did you ever see puffins while diving in the n sea? those birds are some deep divers. amazing.
luckypete, you are right that the threat doesn't have to be there for spikes in the mkt.
however in this case, imho this is a non-event for the most part. why? because ts barry brewed up today when the mkt had closed. barry's projected path makes it short lived over the gulf and takes it n ne through fl & ga, straddling the eastern seaboard. barring any major changes, come monday this storm will be around the new england states.
another point to consider is the concentration of oil platforms and what platforms are in the area is minimal compared with going deeper into the gulf. whats there can be operated by a skelton crew while many systems are automated.
now your point about disruption of marine traffic with shipments from the caribbean headed up the e coast. once again in this example, timing... storm will be far up the coast come monday morning if the projected models bear out. secondly, ships will sit further out off the coast until ts passes by.... but the report did come out and show oil draw downs a couple of days ago lower if i'm not mistaken.
but barry will make the mkt serve notice until the next storm.
have a great weekend pete.
rook
no real threat to offshore platforms./eom
what about the hoa-800 treatment to help viscosity? amep still has until oct on their original agreement.
good morning all, tgif ! :) eom
td alvin and barbara are not a threat to the gulf./eom
sweet. thanks for the share alan. i look forward to learning more about the dome formations. i bet there's some big formations in the world's seabeds.
i'll take for 80,000 shares/eom
thanks alan, i will try to dd about oil dome formations when i get home later. anything you can share on that would be great. tia
good morning all/eom.
info on o & ng reserves in and around the giddings field:
Reserves in Horizontal and Vertical Wells in Faulted Areas (1973-Present).
In areas in southern Lee County, to maximize oil recovered, wells should drill as many faults as possible laterally and two or three laterals into each fault. These horizontal wells can be re-entered upon depletion so other isolated fractures can be penetrated by the horizontal hole above and below the shale barriers that divide the reservoir. Some areas may average one fault every 500 feet (horizontally), while other areas may average one fault per 1,000 feet. Thus, reserves are more related to the number of faults penetrated laterally instead of the length of the horizontal hole. It is easy to conclude a short radius well penetrating a fault by three, four or more short laterals will usually cause large reserves to be developed. Multiple laterals may have less validity when attempting to develop large faults. In such cases one fault may be sufficient. Drilling of long new horizontal holes in some areas may not be advisable because one or more faults may be totally depleted, due to production from vertical wells causing the fluids to interflow between faults which inhibit production to the surface.
Reserves in Horizontal and Vertical Wells in Un-faulted Areas (1973-Present). Reserves in vertical wells in Pearsall Field have historically averaged only slightly more than 30,000 barrels per well in the better producing areas. To this date, these better areas have generally occurred in un-faulted areas. Horizontal wells exceeding 3,000 feet laterally areas in the Pearsall Field may exceed 100,000 barrels of oil per well if depletion has not occurred by the drilling of many offsetting horizontal laterals in the interval being drilled. Southern Burleson County is an area lacking faults where vertical wells regularly attain cumulative production exceeding 100,000 barrels per well. Interestingly, this area in Burleson County is so extensively drained by vertical wells that horizontal wells are often poor producers. In contrast, vertical wells located in eastern Burleson County, adjoining to Brazos County, Texas, in an un-faulted area, average less than 20,000 barrels of oil per vertical well. Horizontal wells in this same area average over 100,000 barrels of oil per well, provided wells are not drilled too close to each other to cause depletion.
More than One Billion Barrels of Oil Remaining to be Developed. The Austin Chalk covers a very large geographic area with over one million acres yet to be developed. The single most important factor controlling the total amount of oil to be found and produced in the Austin Chalk is related to the price of oil and gas. For example, if the price of oil is $50.00 per barrel, then the amount of oil to be produced from the Austin Chalk might exceed 10 billion barrels. Conversely, if the price of oil is $15.00 per barrel, then the amount of additional oil to be produced from the Austin Chalk might be only slightly more than one billion barrels of oil. A substantial part of the shallow Austin Chalk trend south of the Giddings field requires oil prices exceeding $50.00 per barrel.
More than One Trillion Cubic Feet of Gas Remaining to be Developed. Gas oil ratios greatly increase at greater depths. Fayette, Washington, Grimes and numerous additional counties located towards the Louisiana/Texas border yield huge amounts of gas at depths exceeding 10,000-15,000 feet. This development drilling is sensitive to the price of gas. The deep Austin Chalk Trend becomes one of the largest sources of natural gas for Texas when gas exceeds $5.00 per mcf.
gargantuan
my thoughts exactly./eom
good morning all. looks like the gap is filled./eom
pardon, guadalupe county is sw of lee...eom
gudalupe county is se of the giddings field in lee county./eom
here are some historical and economical info on drilling and techniques in and around guadalupe county:
edited:
Large Fracture Treatments, Increased Oil Prices and Seismic Techniques caused Favorable Economics for Wells Drilled Vertically (1973-1986).
Pearsall Field Development by Vertical Wells (1973-1982). The utilization of large fracture treatments in the Pearsall area was a technical breakthrough that caused a large number of wells to be drilled from 1973 through 1976. However, economic projections indicated oil and gas reserves being developed were only marginally economic which caused drilling activity to decline. High oil prices in 1980 and 1981 caused a moderate increase in drilling in Pearsall Field whereas the decrease of oil prices commencing in 1982 resulted in a gradual but significant decrease in activity.
Giddings Field Development (1960-1986). The history of Giddings field is important to the history of the Austin Chalk because Giddings is a field extending into parts of six counties with oil and gas equal to or greater than all other fields. Most techniques to develop Austin Chalk during the last twenty-five years occurred in the Giddings field.
Oil and Gas Development before Introduction of Seismic (1960-1976).
Less than six productive (but not all were economic) wells were drilled in Giddings field from 1960 to 1974. The first producing Austin Chalk well in the Giddings field was the Union Producing Urban #1 well. A well one other well drilled in 1961 by Union Producing (City of Giddings #1 well) was worked over with a small acid treatment in 1973 by Chuck Alcorn producing oil at rates of over 300 barrels of oil per day (BOPD) for several years. Dan and Dudley Hughes drilled four wells during the years 1971 through 1974 with rather poor oil recovery. Houston Oil & Minerals drilled one well in 1976 and twelve wells during the last half of 1977 that also obtained mostly uneconomic results. Prairie Producing drilled three wells with one well being commercial. In 1976, the Windsor M&K #1 well was the first well in Giddings drilled with the consulting firm of RH&A. The M&K #1 well (drilled utilizing subsurface mapping) encountered a fault in the well-bore and with a potential for 463 BOPD after a small acid treatment. All wells drilled prior to M&K #1 well did not utilize seismic or subsurface control to encounter a fault in the Austin Chalk.
Oil and Gas Development after Introduction of Seismic (1976-1986). The Windsor Schkade #1 (the second well drilled by RH&A) was the first well drilled (November 1976) in the Austin Chalk Trend utilizing seismic with the intention of penetrating a fault to encounter associated fractures in the well-bore. Schkade #1 well initially produced oil at rates exceeding 100 barrels of oil per hour. Windsor Carmean #1 well drilled in December 1976 encountered a large gas “kick” The well commenced production in the Buda at 284 BOPD. The clients of RH&A then moved in three rigs to drill at the same time. Windsor Dean #1 well in June 1977 appeared to have noncommercial production after drilling. Pipe was set, but completion was delayed for a study of completion methods. The Fariss #1 well drilled June 1977 also seemed unproductive after drilling. Again, pipe was set with no immediate plans to complete the well. Third well, M.C. Davis #1 well, also drilled in June 1977, had oil shows so poor, the well was temporarily abandoned with no pipe being set. The future of drilling in Giddings field suddenly appeared very grim. Fortunately, Fariss #1 well was fracture treated and commenced production at 717 BOPD. Dean #1 well appeared to be uneconomic but was also fracture treated and started producing at 513 BOPD. Investors again became optimistic and approved the reentry of the M.C. Davis #1 well to set pipe and fracture treat the well which resulted in the well producing 215 BOPD. Humble Exploration, a client of RH&A, made a seven-mile step-out, to the north with the Burtschell #1 well during December 1977 with initial production of 1,094 BOPD. Also, in January 1978, U.S. Operating, another client of H&A, stepped out five more miles further north of the Burtschell #1 well in eastern Lee County and drilled their Gerdes #1 well, which produced 480 BOPD. Investors of Humble Exploration felt very secure about their well, Chicken Ranch #1 well, a fifteen-mile step-out to the south in Fayette County because seismic was being utilized. Chicken Ranch #1 well, drilled in 1978 near LaGrange, had absolutely no oil or gas shows, but produced 1,353 BOPD after fracture treatment. By this time, RH&A reluctantly declined to accept new clients because of the heavy work load. Map 3 show wells drilled through 1977, Map 4 shows wells drilled to the end of 1981, and Map 5 shows wells drilled to end of 1984. Giddings field had five completions in 1976, 57 completions in 1977, 105 completions in 1978, 186 completions in 1979, 628 completions in 1980, and 945 completions in 1981. By December 31 1981, more than 1,900 producing wells had been completed in the Giddings Field. By 1990, 4,200 vertical Austin Chalk wells had been drilled in Giddings field. Clients of RH&A have drilled more than twenty-five percent (25%) of all vertical wells drilled in the Giddings field contained in a six-county area. Majority of all wells drilled in the Giddings field during 1976, 1977, 1978 and 1979 were drilled by clients of RH&A. Giddings field is by far the largest oil and gas field discovered in the state of Texas during the last fifty years.
Developments in Other Austin Chalk Fields by Drilling Vertical Wells (1975-1986). Rising oil prices and fracture treatments encouraged the drilling of many vertical wells. Drilling of Austin Chalk vertical wells in areas outside of Pearsall Field and Giddings Field, for the most part, has had only moderate success since increased activities began in 1975. Many areas in Gonzales County possessed suitable economics in 1980 and 1981 when oil was around $38.00 per barrel, but vertical drilling became increasingly unprofitable as oil price declined to and below $25.00 per barrel. Because the Eagleford Shale is thin (less than 50 feet) with large up-to-coast faulting, present in some areas, vertical wells drilled in Gonzales and Wilson counties often encounter faults allowing movement of water from the underlying Edwards Formation. Several hundred wells were drilled by RH&A with its clients in Atascosa, Wilson and Gonzales Counties, of which the Gonzales wells have been more productive. In general, the area between the Pearsall and Giddings Fields contain many millions of barrels of oil but generally requires significantly higher oil prices for drilling to be economical.
Favorable Economics for Wells Drilled Horizontally (1986-Present). Vertical drilling of oil and gas wells almost ceased in 1986 when oil prices declined to $10.00 per barrel. The hope of the future for the Austin Chalk had to be some new method to increase production for less cost. The business plan for RH&A included the possibility of drilling re-entry horizontal wells at low cost. Unfortunately, due to mechanical failures and inefficiencies of the horizontal drilling tools, horizontal drilling in 1986, 1987, and 1988 was marginally economic. Only in 1989 after major improvements in tool development did economic drilling begin to occur frequently. The low reserves being developed from 1986 through 1988 was mostly related to the drilling tools being incapable of drilling more than 1,500 feet laterally. As discussed in later sections of this report, the combination of being unable to drill long distances and inability to drill more than one lateral were severe limitations. Shale permeability barriers were often the cause for uneconomic re-entry horizontal drilling program during early development of the tools. For the most part, high cost per lateral foot drilled was encountered because the tools were not durable. During 1990, activity continued at a slow pace in the Giddings field. In Burleson County, Union Pacific Resources (UPRC) continued to drill with long radius or large angle medium radius drilling with new and expensive wells costing over $1,500,000. During 1990, UPRC was beginning to obtain some economic success because the expensive horizontal tools could drill a long distance even though they still did not drill more than one lateral hole. Since 1990, UPRC (later acquired by Anadarko) has drilled almost two thousand (2000) horizontal wells in Giddings field to become the largest (by far) user of horizontal drilling. ORYX (then Sun Oil and now a part of Kerr-McGee) drilled a new grass-roots wells in Pearsall early 1988 that produced oil at high rates. New wells drilled by ORYX in the Pearsall field appeared to have favorable economics by the middle of 1989. ORYX continued to drill these new grassroots horizontal wells but cost exceeded $1,500,000. The results of these Oryx wells caused a major increase of horizontal drilling activity in Pearsall field once costs were reduced. Over seventy-five drilling rigs were active in the Pearsall Field area by late 1990. The Pearsall Field drilling activity dramatically decreased by the end of 1990. Due to excessive drilling of horizontal wells in the same zone, severe drainage occurred so extensively that new offsetting horizontal wells were sometimes depleted by offset wells even before they were drilled. Unfortunately, the oil industry once again did not understand rapid depletion was caused by a series of barriers to vertical drainage by shales and short drain holes. Many of these depleted or partially depleted horizontal wells still have large reserves remaining which can be produced by re-entry of existing uneconomic horizontal wells and re-drilling new intervals. It is safe to assume that the development of the Austin Chalk in the future will always occur by horizontal drilling.
Vertical Wells (1950-Present). Acid treatment is one of the most cost efficient and effective procedures the oil industry has ever utilized. Wells began to be acidized in the early fifties. In fractured Austin Chalk reservoirs, acid has been used to clean cement out of the perforations and fractures and/or mud damage fractures with excellent results. Rarely has acid been able to extend the limits of drainage beyond the natural fracture system. Acid treatments seemingly are less successful in the faulted areas, than in the un-faulted micro-fractured areas.
Horizontal Wells (1988-Present). Acid treatments have been used with limited success in horizontal wells in Giddings in faulted areas. For those wells experiencing mud damage or a wall-cake of drilling debris, acidizing may at times be successful in increasing production.
ECONOMIC FRACTURE TREATMENTS (1973-Present).
Massive Hydraulic Fracture Treatments of Vertical Wells with Sand (1973-1986).
The use of fluid exceeding 8,000 barrels of water with 200,000 to 400,000 pounds of sand often yielded excellent initial producing rates in numerous wells in Pearsall Field during 1973-1977 period. Unfortunately, many wells having high initial rates experienced a rapid production decline after receiving the fracture treatments. By 1977, drilling activity greatly decreased in the Pearsall area because the recoveries of oil reserves were too low. Fracture treatments gradually became larger in volumes of fluid and sand, particularly in the Giddings field. The continuing oil price increase and favorable tax laws allowed many drilling programs to be economic through 1981 in Pearsall and Austin Chalk Trend. Most programs in Giddings prior to 1986 were highly successful if a combination of seismic to select locations and fracture treatments were utilized in areas having substantial natural fractures. Since 1986, few vertical Austin Chalk wells have been drilled in the Austin Chalk Trend.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
High Sand Concentrations (1982-1984). A costly technical error occurring in the Giddings area was related to the forceful sales of fracture treatments containing large volumes of sand during the years of 1982, 1983 and 1984 by one service company. Sand concentration of six to nine pounds per gallon with costly treating fluids was utilized with 500,000 to 1,000,000 pounds of sand. Most of these treatments occurred with pumping rates of less than forty barrels of fluid per minute (versus normal 100 barrels per minute) and vertical intervals of less than 100 feet (even 20 feet) instead of the normal 200 foot vertical interval. These fracture treatments would cost double or more of a typical Giddings fracture treatment. Results were poor.
Dendritic Fracture Treatment (1983-Present). Dendritic fracture treatments are not as new as some people believed at that time, but more a reversion back to techniques utilized by some operators in the Oklahoma Mississippi Sooner Trend ten years earlier. This type of treatment is basically a water fracture treatment pumped at rates exceeding 100 barrels per minute. Most of these wells had 60 to 100 deep penetrating "jet" perforations over a 200' vertical interval. The procedure often utilizes small grain sand during treatment to cause abrasion of the fractures and large size sand during the last stages of the treatment to prop open the fractures near the well bore. Results are excellent and low cost.
Fracture Treatments of Horizontal Wells (1989-Present). Fracture treating horizontal wells has yielded results that have not been successful in areas extensively faulted. Faults and large fractures are apparently capable of receiving large volumes of fluid that essentially prevents fracturing of the rocks. Technical capabilities exist to fracture treat a specific interval in the horizontal drain holes but involve excessive cost. Horizontal wells fracture treated in unfaulted areas such as in the northeastern part of Burleson County appear to have yielded increased production. Clayton Williams Energy regularly fracture treated wells in Burleson County with 30,000 barrels of fluid with large amounts of wax beads for diversion.
SEISMIC TECHNIQUES (1976-Present).
Acquisition and Processing Parameters (1976-Present). Part of RH&A's success occurred because of their ability to consistently locate small 25 to 40 foot faults in wells drilled in the Austin Chalk Trend. RH&A determined by trial and error that variations in the acquisition parameters and poor acquisition techniques often caused "disturbances" in the seismic data that exceeded "disturbances" caused by small faults. For these reasons, RH&A kept one to three seismic crews acquiring and processing data with exactly the same parameters. It may be of interest to know that "thumper” seismic data was not as reliable as dynamite data in the Giddings area.
“Seismic Gap" Problems (1976-Present). Some interpreters with limited experience in the area did not understand that the absence of one or two dynamite shots in the seismic line could cause distortions to the data greater than disturbances related to a small 25 foot fault. Several tens of million dollars worth of poor wells were drilled because some seismic interpreters did not realize the difference between a "seismic gap" and a fault. Figure 1 is a seismic line in eastern Lee County.
Seismic "End of Line" Problem (1976-Present). As with the "seismic gap" problem, some seismic interpreters did not understand seismic data was often unreliable near the ends of the seismic lines. Numerous poor wells were drilled because of this error.
Seismic "Quacks" (1977-Present). Some seismic experts with considerable reputations attempted to convince the industry certain seismic data processing techniques could assist in locating fracture porosity. One possible technical explanation why seismic data does not accurately predict fracture porosity (fractures) in the Austin Chalk is best explained if one is aware only 1% or less of fracture porosity occurs in the Austin Chalk. Small amount of porosity increase by fractures is much too small of a volume change to be recognized by seismic techniques over short lateral distances. Information was generated to drill horizontal wells based on this flawed technical concept.
HORIZONTAL DRILLING (1986-Present).
Learning Curve (1986-1989). Attempts with short radius tools for horizontal drilling has occurred for almost fifty years with no economic success until the mid 1980s. During the 1970's and early 1980's, long radius drilling was utilized but again was mostly uneconomic except for applications in oil fields with large oil and gas reserves such as Prudhoe Field in Alaska because of the large cost. Elf Aquaitane was one of the more active early operators using long radius technology in the early 1970's. Figure 3 shows the different types of horizontal tools. The years 1986 through 1989 were very difficult times utilizing medium radius horizontal drilling. Cost generally was two to four times more expensive than today on a "dollars per lateral foot" basis. Drilling bits would drill four to six feet an hour now drill 10 to 60 feet per hour. Life of tools between repairs and/or replacement was 10 to 25 hours compared to 100 to 250 hours at the present time. Proper reservoir description during the early years was a major problem preventing the production of all mobile oil. In particular, oil industry at that time did not understand the Austin Chalk interval consisted of many separate reservoirs because of the many shale (ash) intervals in relatively un-faulted areas or areas with small faults. Figure 2 portrays the frustration during the early years of development of horizontal drilling.
Medium Radius Drilling Tools Allowed Horizontal Drilling to be Economic (1985-Present).
ARCO Working with Christensen in New Mexico and West Texas (Large Holes, New Wells, 1985-1986). ARCO began development of tools working with Christensen in new grassroots wells with hole sizes larger than 9 inches. This special knowledge and experience was almost lost in 1986 because both ARCO and Christensen disbanded their horizontal drilling groups at the time of the oil depression with the tools being stored in a warehouse and not being utilized during the last half of 1986 and all of 1987. ORYX began to use this technology in Pearsall field commencing at the end of 1987.
Holifield Working with Bechtel Investments, Inc. in Austin Chalk Formed BecField Horizontal Drilling Services (Small Holes, Re-entries, 1985-1991).
The experimental tools being developed by Bill Maurer and Bechtel Investments began to be utilized in Giddings field to re-enter existing well bores. It was hoped that re-entry horizontal drilling would generate excellent economic returns because of low cost. BecField Horizontal Drilling Services was formed by B. Ray Holifield and Bechtel Investments to introduce this new re-entry technology to the oil industry. BecField drilled seven re-entry wells in 1987, 23 re-entry wells in 1988 and 42 re-entry wells in 1989, and 96 re-entry wells to September, 1990 (when Holifield sold his interest in BecField) of which most horizontal wells were drilled out of 5-1/2 inch cased wells. This drilling by BecField represented over 50% of all horizontal wells drilled in the USA during that time.
Union Pacific Resources Company (now Anadarko) in Giddings Field (1988-Present). UPRC has drilled over 2000 horizontal wells in the Austin Chalk trend to this date. UPRC utilizes their experience in horizontal drilling in many geographic areas at this time. UPRC drilled mostly new grass-roots horizontal wells until 1997. Thereafter, UPRC become very active in re-entry of existing wells in those areas having existing wells.
Service Companies Become Competent in Medium Radius Horizontal Drilling (1989-Present). As service companies became more adept at utilizing the technology, costs greatly decreased. The ability to efficiently drill out of casing as small as 4-1/2 inches was developed. It is now common to multilateral drill two or more stacked laterals 4,000 feet in one direction and then from the same well drill two or more laterals 4,000 feet in the opposite direction.
Short Radius Drilling Tools Developed that Work Economically (1994-Present). Utilization of short radius horizontal drilling tools first became economic in 1994 in New Mexico and Oklahoma. Articulated down-hole drilling mud motors were developed that allowed precise directional control and predictability not previously available in short radius drilling operations. At this time, most of the service companies have excellent short radius drilling systems utilizing down-hole mud motors. Flexible (but expensive) composite drill pipe allow rotation of pipe for curves as small as thirty feet. Short radius wells can be drilled with much cheaper metal drill pipe if curves are greater than 70-80 feet. The best use of short radius tools is to develop fault related fractures near existing well-bores, particularly in the Upper Austin Chalk, near faults in the Lower Austin Chalk and Buda.
PROBLEMS IN DEVELOPMENT OF OIL AND GAS IN THE AUSTIN CHALK BY HORIZONTAL DRILLING (1986-Present).
Vertical Barriers to Flow of Fluids (1986-Present). Initially, depletion from offsetting vertical wells was believed to be the cause of many of the poor horizontal wells in the Giddings field, but that was not true in most cases. Many of the early horizontal wells in Giddings commenced initial production at several hundred to over one thousand barrels of oil per day with high flowing pressures which certainly eliminates the depletion theory. The real cause of low reserves at that time was that only one fault had been penetrated by one short distance lateral well-bore limited vertically to very thin zones by shales. To workers previously involved with the drilling and completions of vertical wells, the determination of the effectiveness of shale beds in the Austin Chalk reservoir to prevent the extension of fractures through the shales was astonishing. Evidence confirmed that it is possible for shale, only inches in thickness, to prevent significant migration of fluids either up or down into the adjoining fractured intervals. The soft un-fractured shales are not permeable; consequently, the shales limit production. These shale beds are also the culprits causing ultimate recoveries in Pearsall Field to be so low. The proper application of this knowledge of these barriers to vertical permeability offers tremendous opportunities. Many of these so-called depleted horizontal wells still contain large reserves of oil that can be developed economically by the drilling of new laterals utilizing existing horizontal wells. RH&A predicts most horizontal wells drilled to date in the Austin Chalk will be re-drilled laterally two, three or more times. Conclusions of this paragraph concerning vertical separation by shales are often not applicable if large faults are present.
Water Production (1986-Present). Water production from the underlying Edwards Formation can be a serious problem where the Eagleford Shale is thin in areas having large faults. For example, in no case has formation water been produced in Lee County where the Eagleford is often greater than one hundred (100) feet thick with displacement of faults usually twenty to forty feet.
Depletion of Faults (1986-Present). In mature areas where many vertical wells have been drilled, it is possible for a horizontal well to encounter numerous faults with one or more faults being depleted and with other faults having original pressures. In such cases, interflow of fluids between faults instead of to the surface is a serious problem. Short radius drilling to develop individual faults can solve many of these problems.
call a spade a spade, but don't make up stuff. you were ripped because of inmature posts.
pro, apparently you have not learned anything.
lol./eom
poundhound. i see the captain may get recalled by mclaren, he should have never been dropped.
so does poundhound have anything to do with the love of the quid?
good morning. thank you all and god bless to those who have served and to those doing so.
korean was about about stopping the commie aggression from the north. started when they invaded the republic of korea and was backed by the ussr and china. thank you to your dad! :)
Current Statistics...
*- February Permits To Drill
The Commission issued a total of 1,400 original drilling permits in February 2007 compared to 1,546 in February 2006. The February total included 1,191 permits to drill new oil and gas wells, 39 to re-enter existing well bores, and 170 for re-completions. Permits issued in February 2007 included 242 oil, 355 gas, 721 oil and gas, 59 injection, zero service and 23 other permits.
*- January Crude Oil Production
Texas preliminary January 2007 crude oil production averaged 876,817 barrels daily, down from the 909,801 barrels daily average of January 2006. The preliminary Texas crude oil production figure for January 2007 is 27,181,330 barrels, a decrease from 28,256,157 barrels reported during January 2006.
*- February Oil and Gas Completions
In February 2007, operators reported 429 oil, 681 gas, 31 injection and seven other completions compared to 432 oil, 695 gas, 39 injection and one other completion during February 2006. Total well completions for 2007 year to date are 2,599 up from 2,053 recorded during the same period in 2006. Operators reported 530 holes plugged and three dry holes in February 2007 compared to 310 holes plugged and zero dry holes in February 2006.
*- January Natural Gas Production
Texas oil and gas wells produced 469,810,569 Mcf (thousand cubic feet) of gas based upon preliminary production figures for January 2007, up from the January 2006 preliminary gas production total of 437,124,806 Mcf. Texas production in January 2007 came from 135,961 oil and 75,466 gas wells.
*- February Texas Oil & Gas Drilling Permits and Completions by District
RRC District: (1) SAN ANTONIO AREA
Permits To Drill Oil/Gas Holes: 50; Oil Completions: 11; Gas Completions: 15
RRC District: (2) REFUGIO AREA
Permits To Drill Oil/Gas Holes: 54; Oil Completions: 7; Gas Completions: 41
RRC District: (3) SOUTHEAST TEXAS
Permits To Drill Oil/Gas Holes: 70; Oil Completions: 37; Gas Completions: 17
RRC District: (4) DEEP SOUTH TEXAS
Permits To Drill Oil/Gas Holes: 107; Oil Completions: 6; Gas Completions: 93
RRC District: (5) EAST CENTRAL TEXAS
Permits To Drill Oil/Gas Holes: 63; Oil Completions: 1; Gas Completions: 33
RRC District: (6) EAST TEXAS
Permits To Drill Oil/Gas Holes: 164; Oil Completions: 11; Gas Completions: 139
RRC District: (7B) WEST CENTRAL TEXAS
Permits To Drill Oil/Gas Holes: 67; Oil Completions: 25; Gas Completions: 21
RRC District: (7C) SAN ANGELO AREA
Permits To Drill Oil/Gas Holes: 143; Oil Completions: 32; Gas Completions: 84
RRC District: (8) MIDLAND AREA
Permits To Drill Oil/Gas Holes: 236; Oil Completions: 156; Gas Completions: 19
RRC District: (8A) LUBBOCK AREA
Permits To Drill Oil/Gas Holes: 106; Oil Completions: 88; Gas Completions: 7
RRC District: (9) NORTH TEXAS
Permits To Drill Oil/Gas Holes: 262; Oil Completions: 41; Gas Completions: 143
RRC District: (10) PANHANDLE
Permits To Drill Oil/Gas Holes: 78; Oil Completions: 14; Gas Completions: 69
Top Ten Crude Oil Producing Counties
County
Barrels
1) Gaines
2,296,160
2) Andrews
2,021,146
3) Yoakum
2,020,632
4) Hockley
1,562,757
5) Ector
1,494,161
6) Scurry
1,344,972
7) Pecos
958,325
8) Upton 916,713
9) Midland
903,702
10) Crane
750,070
Top Ten Natural Gas Producing Counties
County
Mcf (thousand cubic feet)
1) Zapata
24,622,547
2) Panola
22,166,269
3) Freestone
20,233,405
4) Hidalgo
18,518,702
5) Webb
17,244,875
6) Pecos
16,134,971
7) Wise
13,258,044
8) Tarrant
12,176,594
9) Denton
11,688,239
10) Johnson
10,713,510
nice reply slippery wing. here are techologies and a bit of the history and the importance they have played regarding drilling.
edited
Acid Treatments (1950's). Acid treatment of wells caused considerable development during the 1950's in Pearsall Field of Frio County, Texas and several other smaller, shallower fields. Unfortunately, activity greatly subsided because of rapid declining production rates. Acid treatments are usually not required for wells drilled horizontally.
Large Fracture Treatments (1973). Small scale fracture treatments occurred before 1973. Large amounts of treating fluid and sand injected into wells at high rates. From this apparent success, large amounts of drilling dollars were spent in Pearsall field. A few other small fields were active for a period such as Mag Field in Gonzales. With time, results were only marginally successful. Drilling declined significantly during late 1976 in the Pearsall area. However, activity in Giddings field increased in 1976 and has continued to this date. Many of these wells in Giddings were placed onto production without fracture treatment. However, many wells with little indication of production (except being near a fault) were fracture treated and produced large quantities of oil and gas. Fracture treatments of wells are usually not required for horizontal wells.
Seismic (1976). A true revolution in the development of oil ands gas reserves in site locations using both 3-D and 2-D.
Horizontal Drilling (1985). In the United States, horizontal drilling dates back to the 1920s-1930s, with the first technically successful applications attempted in the 1940s. It was not until successful horizontal wells were drilled in Rospo Mare in Italy, and the first horizontal well was designed and drilled on the North Slope of Alaska before the oil industry began to give horizontal drilling a chance. In 1986, there were only 39 wells drilled worldwide. Horizontal drilling has been attempted for over fifty years but the technology was not economic until medium radius horizontal drilling commenced.
Medium Radius Horizontal Drilling (1985). Testing of equipment in actual field conditions began in 1985 in Giddings field. Initially, “under the river” drilling tools were modified in 1985 by Maurer Engineering with a $1,700,000 research project funded by Bechtel Investments, Inc. The first reentry medium radius horizontal well drilled in an oil field anywhere in the world occurred in the Giddings field in Fayette County, in a well operated by J&G Operating Company, a small Houston operator in 1986. The well was drilled as a reentry of a 5-1/2 inch cased oil well. Before 1991, horizontal wells were usually being drilled with one lateral for short distances in Pearsall and Giddings fields which opened only a small part of the total reservoir rock. Since then, wells with multiply and long laterals have greatly increased oil and gas recovery. By 1997, reentry of existing vertical wells became the preferred technique. Frequently two or more lateral are being drilled.
Short Radius Horizontal Drilling (1999-Present). This technology is successful in certain faulted areas. For example, many wells located in Lee County are perfect candidates. However, un-faulted areas such as Burleson County may not be very successful. This technology will become a standard technique for certain situations.
Multilateral Wells (1992). Multilateral well refer to any well where more than one branch is made into a reservoir from the main trunk or wellbore in order to maintain or increase productivity of the well. The first dual horizontal well completion was accomplished by Torch Energy Advisors in 1992. Maersk also drilled the first multilateral horizontal in the North Sea in 1992. Simple uncased and cased “branches became technically feasible in 1994-1995. The uncased well advancement by industry was propelled by companies drilling opposing and stacked laterals out of the parent wellbore. The leading operator in the 1990s advancing the drilling of these type wells was Union Pacific Resources. This more complex architecture allowed for crossing more fractures and provided greater reservoir exposure for Austin Chalk wells, and allowed for draining more than one horizon. In Texas, there are many irregular shaped leases, and this technique allows for better exploitation of the resource.
Underbalanced or Controlled Pressure Drilling (1964). While the first documented approach to drilling with underpressure occurred in design in the 1960s, commercial application occurred largely because of development of this technology in the Austin Chalk Trend, principally in the late 1980s-early 1990s. By using a simple low pressure flow diverter while drilling, Chalk drillers learned to flowdrill with pressures approaching 600 pounds to 800 pounds at the wellhead. This allowed for much more efficient and economic horizontal drilling of the critical zones. This type drilling was important to apply because of the nature of crossing depleted and un-depleted fractures in the Austin Chalk Formation. Later a company by the name of Williams Tool Company developed a more powerful diverter which could take much higher underbalanced pressures, causing a step change in making many more wells economically feasible to successfully drill and complete.
3 Americans, 4 Britons kidnapped in Nigeria
Oil workers were taken by gunmen in unruly petroleum-producing region
NBC World Blog
Updated: 5:55 a.m. PT May 25, 2007
Gunmen kidnapped a group of foreign oil workers on Friday, including three Americans and four Britons, in Nigeria’s unruly southern petroleum-producing region, officials said.
Security forces in the region earlier said only six people were kidnapped, including an Indian, but details released by U.S. and British embassy officials put the number at at least seven.
The embassy officials both spoke on condition of anonymity, citing standard agency prohibitions against their names appearing in public.
The latest abduction to hit Africa’s oil giant took place in southern Bayelsa state, said Joshua Benemesia, a leader of an unarmed, government-funded group that helps provide security in the state. He said six foreigners were taken, including an Indian. All were aboard a boat owned by a Nigerian oil-services company, he said.
On Thursday, five gunmen grabbed a Polish worker heading to his construction project in southern Nigeria and rushed the captive into the lawless oil-rich region’s swamps and creeks in a speedboat, officials said.
Security forces were trying to make contact with the hostage takers, who grabbed the man on his way to work in the southern city of Warri on Thursday, said Brig. Gen. Lawrence Ngubane, a military commander in the region.
The kidnappings are the latest in a run of more than 100 seizures of foreign workers this year in the oil-producing Niger Delta, where all of the crude is pumped in Africa’s largest producer.
Some 200 foreign workers have been taken since militants stepped up their attacks against the oil companies and government in late 2005, cutting nearly one third of Nigeria’s daily crude production capacity and sending oil prices toward historic highs in oversees markets.
The militants say they’re fighting for the liberation of two of their leaders imprisoned on corruption and treason charges and more oil revenues for their impoverished lands.
But in recent months, criminal gangs have taken up the practice of kidnapping foreigners for ransom. Hostages are generally released unharmed after a payment is made to the captors, although two died in the crossfire when security forces intervened.
Nigeria is Africa’s biggest oil producer and a top supplier of crude to the United States.
© 2007 The Associated Press. All rights reserved. This material may not be published, broadcast, rewritten or redistributed.
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ps ~ farm, what a whiner. you should be happy with royalties...and if you think you aren't getting paid enough, you or someone in your family wasn't a very good negotiator... lmao
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coach, can't private msg, ty. buddrow, keep searching the trrc using proco and search by pri, production resoures, inc. there's actually a wealth of info on this board alone on reported production on the various leases (courtesy of contractor, et al...you know who you all are!). which is growing i might add :)
coach, i hear what you are saying and you and i know that worms with agendas whether hidden or not will always try to derail and smear others in the process.
the texas railroad commission is a regulatory agency and provides wealth of info for the taking. you certainly can't fudge what the trrc post. if you haven't navigated the sight, i'd suggest doing so.
here's the link: http://www.rrc.state.tx.us/
i'm just ready for this to fly mac! we are all due. let's hope this puppy has seen the last of this sp level.
how about the open! 4.42% :)
good morning all. coach, was there ever a doubt? :) 2005 o & g map of tx: http://www.beg.utexas.edu/UTopia/images/pagesizemaps/oilgas.pdf
can you say darst creek-buda:
Giddings field, the largest field in a 10- to 20-mile-wide trend (figs. 1, 16), extends from Mexico through Central Texas and into northwest Louisiana. The primary producing reservoir is the Austin Chalk (Upper Cretaceous, 85–90 million years old), with secondary production from the Taylor (Upper Cretaceous) and deeper Buda and Georgetown Formations (Lower Cretaceous, 98–105 million years old). Today the Austin Chalk outcrops at the surface along a belt that runs from Del Rio on the Texas-Mexico border, northeast through San Antonio, then north through Austin, Waco, and Dallas. The Chalk then dips gently (2°) to the southeast into the subsurface. In Giddings field, the Austin Chalk reservoir ranges in burial from 5,500 ft TVD in Milam County to over 15,000 ft TVD in Austin County. The Austin Chalk (as well as the Buda and Georgetown) is a fractured carbonate reservoir, with limited matrix porosity (1–5%) and permeability (0.003–0.03 md). The Austin Chalk in Giddings field, ranging from 150 to 750 ft in thickness, consists of interbedded chalk and marl (limestone with shale). It was deposited in a low-energy, open-marine setting, where very fine calcium carbonate debris could settle slowly to the seafloor. Most hydrocarbon production in the Austin Chalk comes from an extensive network of fractures. Localization of these fracture networks is controlled by bending of the formation in areas with a gentle southeast dip. Clean chalk beds fracture when bent, whereas the marl/shale beds will not. Local disturbance by salt domes also influences fracture development. The updip (northwest) limit of Giddings field is defined by the burial depth of the Eagleford Shale. This shale was deposited between the Austin Chalk and underlying Buda/Georgetown rocks. The Eagleford Shale contains carbon-rich layers that serve as the hydrocarbon source, when buried to sufficient depths. Where it is not buried deep enough to generate oil and gas (northwest of Giddings field), the Cretaceous reservoirs are not productive. The downdip (southeast) limitation is primarily technology. As depth to the reservoir increases, temperature and pressure increase such that current drilling and LWD (logging while drilling) technology is insufficient to drill economic horizontal wells.
lol. where have you been hiding manitou? things to make you go hmmmmm about the buda:
tidbits on the buda
Lower Cretaceous formation mapped in discontinuous, highly faulted, northeast-southwest trend in Uvalde, Medina, Bexar, Comal, and Hays Cos, TX (Ouachita tectonic belt province). Overlies Salmon Peak Limestone (Lower Cretaceous) west of Dry Frio River, overlies Devils River Limestone (Lower Cretaceous) between Dry Frio River and Medina River, overlies Edwards Limestone (Lower Cretaceous) east of Medina River, and very small local areas of Del Rio are mapped in northwestern part of map sheet in Real and Kerr Cos, TX (Kerr basin) where Del Rio overlies Segovia Member of Edwards Limestone. Overlain by Buda Limestone (Lower Cretaceous). Del Rio, Buda, and overlying Eagle Ford (Upper Cretaceous) locally faulted-out entirely (e.g. eastern Medina and western Bexar Cos, TX). Map unit described as clay, calcareous and gypsiferous becoming less calcareous and more gypsiferous upward, pyrite common, blocky, medium gray, weathers light gray to yellowish gray; some thin lenticular beds of highly calcareous siltstone; marine megafossils include abundant Exogyra arietina and other pelecypods; thickness 60-120 ft, thickens westward. [Explanation on map sheet shows Buda and Del Rio as Upper Cretaceous, but pamphlet that accompanies map shows Buda and Del Rio as Lower Cretaceous.
The upper Comanchean Buda Limestone (Cretaceous) is a known reservoir for hydrocarbons in central Texas, producing from depths as shallow as 700 ft.^Understanding the character of the Buda Limestone and its complex depositional and diagenetic history is essential to developing a sound exploration strategy and to insure maximum production.^In central Texas, the Buda Limestone may be divided into a lower, micritic facies, and a dense, in places dolomitized, intrasparite upper facies.^The upper Buda is more porous and contains most of the producible hydrocarbons in the formation.^The upper contact is an undulating erosional surface, unconformably overlain by impermeable Woodbine shales.^Porosity enhancement appears greater in areas of faulting and fracturing, especially where occurring along erosional drainage divides.^Because of the apparent correlations between favorable structure and marketable oil production, economic prospecting methods should seek to delineate zones of faulting and fracturing along areas where the upper Buda was exposed to weathering.
BUDA STRIKES MAY BOOST SOUTH TEXAS ACTION
G. Alan Petzet Senior Staff Writer Cretaceous Buda limestone oil production has been established in an area of South Texas that could give further impetus to the already hot Austin chalk horizontal drilling play. Two wells almost 1 1/2 miles apart in Frio County, Tex., along the Atascosa County line have begun producing oil at high rates from Buda. The wells appear to be zone discoveries in the same fault block in Pruitt (upper Cretaceous Navarro) field, about 15 miles east of Pearsall, Tex.
The Buda formation is a naturally fractured limestone.^Initial production is limited by low matrix permeability and possible plugging of existing natural fractures during the drilling and completion of the wells.^Consequently, proppant fracturing is an integral part of the completion of Buda wells.^Within the last year, Gulf Oil Exploration and Production Company has completed 12 wells in the Buda lime.^During the fracturing treatments, 4 screenouts occurred on the first 7 wells treated.^Laboratory data indicated that a different fluid loss program minimize screenouts in naturally fractured reservoirs.^This technology was applied to the Buda wells.^Using 100 mesh particles in conjunction with fine oil soluble resins, only 1 screenout was observed in the next 5 treatments.^Laboratory data, treatment design, and well performance are presented in this paper.
cocoa, how about some new dirt afar, like near san antonio? contractor alluded to it yesterday.
contractor, allow me to take a stab at the next adjective after huge ? you posed, if i may.
would gargantuan suffice?
work is over and i'm out the door. :)
ah, my brain was going faster than the fingers. thanks for catching that... yes it should read 4%+