Tuesday, October 29, 2019

Superdeep Borehole into The Earth

The drill bit has stopped turning and the KTB project is winding down. Germany's superdeep borehole is complete. How and why was it drilled? And what have the scientist achieved so far?

 Thermal gradients, heat production, stress fields, fluid transport, deep seismics and deep resistivity are all of great interest to earth scientist. Studying these fundamental topics helps them unravel the mysteries of weather fluctuations, the distribution of mineral resources, and natural disasters such as earthquakes, volcanoes and floods. Rock outcrops, river gorges and cliff faces provide visual evidence to interpret deep probing measurements such as seismics, magnetics and gravimetrics. Commercial mining and drilling have also guided scientist , giving tangible connections to surface observations. However, drilling has been used specifically for scientific research only within the last thirty years.

The internationally funded Ocean Drilling Program (ODP) was started as part of a worldwide effort to research the hard outer layer of the Earth's crust called the lithosphere. Results from this project have been dramatic, providing real evidence of continental drift and plate tectonics. The lithosphere is made up of six major and several minor rigid moving plates. New oceanic crust is formed and spreads out at mid-ocean ridges and is consumed at active plate margins-subduction zones- where it sinks back into the Earth's mantle. This process takes up to a few hundred million years. 

Continents are different. They are made of lighter rock and are not easily recycled, allowing them to achieve ages of 4 billion years. They also provide the vast majority of the world's resources , so it is vital to understand their structure and development. One way of doing this is to extend the work started by ODP to the continent. KTB- which stands for Kontinentales Tiefbohrprogramm der Bundesrepublik Deutschland, or German Continental Deep Drilling Program- is drilling one of a handful of borehole specifically for continental scientific research. This article looks at the major drilling achievements of KTB, at the Schlumberger wireline logging contribution and at some of the main areas of research. 

The project was initiated in 1978 by a working group of the German Geoscientific Commision of the German Science Foundation. The group discussed more than 40 possible drillsites in Germany, eliminating all but those with the broadest possible research potential. Two sites were chosen for further studies: Haslach in the Black Forrest region of South Germany and Windischeschenbach 80 km east of Nurnberg in Bavaria, southeast Germany. In 1985, the Federal Ministry for Research and Technology gave the final approval for the KTB deep drilling program and both sites were comprehensively surveyed. 

Both geology and the expectation of a lower formation temperature gradient favored the Windischescenbach site. The site is located on the western flank of the Bohemian Massif about 4 km  east of a major fault system- the Franconian line.Scientists also believe it lies at the boundary of two major tectono-stratigraphic units in Central Europe- the Saxothuringian and Moldanbuian. This boundary- which they hoped to cross - is regarded as a suture zone formed by closure of a former oceanic basin 320 million years ago. This process gave rise to a continent-continent collision- forming a mountain chain and the present day Eurasian plate. The mountains have long since eroded away, exposing rocks that were once deeply buried. Therefore, this area is ideal for the study of deep-seated crustal processes. In addition, geophysical surface experiments have shown that the area around the drillsite has unusually high electrical conductivity and strong gravimetric and magnetic anomalies, which deserve closer investigation.

The scientific challenges for the KTB project all contribute towards understanding the fundamental processes that occur in continental crust. Among these are earthquake activities and the formation of ore deposits.The primary objectives, therefore, were to gather basic data about the geophysical structure below the KTB site, such as the magnitude and direction of stresses, so that the evolution of the continental crust might be modeled. Information about thermal structure - temperature distribution, heat sources and heat flow- was also needed to understand chemical processes such as the transformation to metamorphic rock and the mineralization of ores. Fluids also play an important role in temperature distribution, heat flow and the various chemical processes, so measurements of pressure, permeability and recovery of fluids found were also important.

The overriding goal of the KTB project was to provide scientist with a permanent, accessible, very deep hole for research. With a budget of 498 million Deustche Marks [ $319 million] - provided by the German government- the initial target was to drill until temperature reached about 300 degree celcius [527 F] -expected at a depth of 10,000 m to 12,000 m [32,800 ft to 39,370 ft] - the estimate limit of borehole technology. This includes drilling hardware, drilling fluid chemistry, cementing as well as the downhole instrumentation required for the various scientific experiments. Many technical spin-offs developed from the project. 

Drilling the Vorbohrung - Pilot Hole

It is not common to drill through sufical crystalline rock especially when the drilling conditions are unknown. Kola SG 3, on the Kola peninsula near Murmansk, Russia, is one exception. It is the world's deepest borehole, but not an ideal role model. After 15 years of drilling, at an untold cost, the borehole reached a depth of 12,066 m [ 39,587 ft]. Years later it was deepened to 12,260 m [ 40,220 ft].

The project management team, having studied the Russian project, decided to first drill a pilot hole - KTB Vorbohrung. This was spudded on September 22, 1987. The objectives for the pilot hole were as follows:

  • Acquire a maximum of geoscientific data, from coring and logging the entire borehole, at low cost and minimum risk before committing to an expensive heavy rig and superdeep hole.
  • Minimize core runs and logging in the large-diameter, straight vertical upper section of the superdeep hole.
  • Analyze the temperature profile for planning the superdeep hole.
  • Obtain data about problem sections with inflow or lost circulation, wellbore instabilities and breakouts.
  • Test drilling techniques and logging tools in preparation for the superdeep hole.

 To accomplish these objectives, a new drilling technique was developed that combined rotary drilling and sandline core retrieval techniques. A modified land rig used a high-speed topdrive to rotate internal and external flush-jointed 5 1/2-in. outside diameter mining drillstring in a 6-in. borehole. This drillstring provided enough clearance inside to allow 4-in. cores to be cut and pulled up to surface through the drillipe by sandline- eliminating round trips to recover cores. A solids-free, highly lubricating mud system had to be used, because of the small clearance between the flush external surface of the drillstring and the borehole wall. This coring method worked well until February 1989 when excessive corrosion in the pipe joints required replacing the mining string with conventional 3 1/2-in. externally upset drillpipe and core  barrels.

Coring operations had to be interrupted on other ocassions - three times for directional drilling to bring the hole back to vertical and twice for sidetracking, because of lost bottomhole assemblies after unsuccessful fishing.However, a total depth (TD) of 4000 m [13,124 ft] was reached for KTB-VB on April 4, 1989, after 560 days of drilling and logging. More importantly, 3594 m [11,790 ft] of cores were recovered a recovery rate comparable to those achieved worldwide in easier formations - and the hole was extensively logged with many different instruments.

The drilling experience in KTB-VB proved invaluable to the planners of the superdeep borehole. For example, they encountered areas of borehole instability across fault zones; they had to modify the mud system to account for water influx and water-sensitive rock; they had numerous breakouts caused by the relaxation of stressed rock; and the formation dipped more steeply than predicted making it difficult to keep the hole anywhere near vertical. In total, the pilot hole presented a greater challenge for drillers than expected. 

For the next year, many experiments and measurements- such as hydrofracs, production tests and extensive seismic work - were carried out in around KTB-VB. In April 1990, the hole was finally cased and cemented. 

Drilling the Hauptbohrung

The superdeep hole- KTB Hauptbohrung (KTB-HB) - was spudded on October 6, 1990, and reached a TD of 9101 m [29,859 ft] on October 21, 1994. To drill to this depth in only four years required the design and construction of the largest land rig in the world- UTB 1. This rig could handle 12,000 m of drillpipe that required a maximum hook load of 8000 kN [1,800,000 lbf] -more than three times that of the rig used to drill KTB-VB. Mechanical wear and tear was expected to correspond to drilling 30 deep conventional wells, with over 600 round trips. Reducing trip time called for radical rig design. Using 40-m [130 ft] stands of drillpipe instead of the standard 27-m [90 ft] stands save 30% of the time. However, long drillpipe stands meant the rig had to be 83 m [272 ft] high.

To further increase trip efficiency, an automated pipe handling system was installed. This consisted of a 53-m [174-ft] high pipehandler that grasped and lifted stands of drillpipe between the rotary table and star-shaped fingerboard for stacking in the derrick. This allowed the pipehandler to operate while the traveling block was moving.

The entire operation was controlled by a driller, pipehandler operator and two floormen. Only the floormen worked outside on the rig floor- the other two sat inside a control room at consoles equipped with video screens and gauge. Computers controlled many of the operations of the pipehandler. Using a pipe conveyor to lift single pipes between rig floor and pipe racks saved additional time.

Borehole torque and drag as well as the strength of the drillpipe are decisive factors when it comes to reaching great depths quickly and safely. Torque while drilling and excessive hook loads when pulling the string are caused by lateral forces and friction between drillstring and borehole wall. These two factors are increased by the weight of drillstring, borehole inclination and severity of any doglegs. Borehole trajectory influences not only drillstring design, but also any proposed casing scheme. A slim-clearance casing scheme cuts down on rock volume drilled, but also requires a near vertical borehole to minimize friction. Without active steering the borehole would start to build angle as was proved in KTB-VB. So KTB commissioned Eastman Christensen- now Baker Hughes Inteq- to develop a self-steering vertical drilling system (VDS). 

The VDS system consisted of a positive displacement motor to drive the drill bit, a battery-powered inclinometer to measure deviation and a hydraulic system to adjust the angle of the drill bit to correct for deviation. Two hydraulic systems were used  : the first system operated external stabilizer ribs that pushed against the borehole wall moving the whole VDS assembly back to the vertical; the second system used internal rams to move the shaft driving the drill bit back to vertical. As long as battery power was maintained to the inclinometer, both systems operated automatically. Inclination, and other parameters such as temperature, voltage and systems pressure, were transmitted to surface by a mud pulser to monitor progress.

The first 292 m [958 ft] of KTB-HB were drilled with a 17 1/2 in. bit and opened up to 28 in. before setting the 24 1/2 in. casing. To meet the requirements of a vertical hole, a 2.5 degree correction to deviation was made as the hole was widened. The next section was drilled with a 17 1/2 in. VDS system to 3000 m [9840 ft] and completed at the end of May 1991. Teething problems with prototype VDS systems meant using packed-hole assemblies (PHAs) during maintenance and repair. Even so, average deviation for this section was less than 0.5 degree. 

The same strategy was used for the 14 3/4 in. hole - alternating between the improving VDS systems and PHAs. A high deviation buildup from 5519 to 5596 m [18,107 to 18,360 ft] during one PHA run led to the borehole being pulled back and a correction made for deviation. The hole continued on course to 6013 m [19,728 ft] where 13 3/8-in. casing was set in April 1992 - horizontal displacement at this stage was less than 10 m [33 ft].

Drilling continued with VDS systems and PHAs and 12 1/4-in. bits. Within this section 45.7 m [150 ft] were cored, including 20.7 m [68 ft] with a newly developed, large-diameter coring system that gave 9 1/4-in. diameter cores. However, in July 1992 at 6760 m [22,179 ft], the bit became stuck. Eventually, after an unsuccessful fishing operation, the hole had to be plugged back to 6461 m [21,198 ft] and sidetracked. In March 1993, over an interval of 6850 to 7300 m [22,474 to 23,950 ft], a major fault system was crossed. The VDS system could not control deviation over this interval and another correction had to be made. This system was thought to be an extension of the main fault that lies along the boundary between sediments to the west and metamorphic rocks to the east- the Franconian line. Along this fault system a displacement of more than 3000 m occured, showing a repetition of drilled rock sequences. This signaled the start of the most difficult drilling yet and additional funds had to be provided by the German government to complete the project - bringing the total cost to $338 million.

At 7490 m [24,573 ft], when the horizontal displacement was only 12 m [39 ft] , the VDS system was abandoned, as borehole temperatures became too high for the electronics. The hole then started to deviate north. 

Within the main fault system the borehole became unstable and more breakouts occured. While tripping out-of-hole stuck at 7523 m [24,682 ft]. Jarring eventually broke the downhole motor housing allowing the pipe to be pulled out but leaving behind a complicated fish. Several attempts to retrieve the fish failed and the hole was finally plugged back to the vertical section - at 7390 m [24,245 ft] - and sidetracked. Drilling again proved difficult and so a 9 5/8-in. liner was set at 7785 m [25,541 ft] in December 1993 to protect this hard-won section of hole.

Difficult drilling continued with a 8 1/2-in. bit down to 8730 m [28,642 ft]. Borehole instability prevented further progress and a 7 5/8-in. liner was set in May 1994. To bypass the unstable section, a sidetrack was made at 8625 m [28,297 ft] through a precut window in the liner. Funds to continue drilling were now running low and a decision was made to stop 476 m [1561 ft] later on October 12, 1994. More than four years after spudding, the hole had reached 9101 m with a final bit of 6 1/2 in. However, the borehole had not finished with the drillers yet. Attempts to lower logging tools into the open hole failed. The last section had to be re-drilled and a 5 1/2 -in. liner set, leaving only 70 m [230 ft] of open hole for the wireline loggers and other scientific experiments. 

Data Collection and Analysis

The main center of scientific activity at KTB was the field laboratory with a staff of 40 including resident scientist and technicians. Here, experiments were performed on cores - mainly from the KTB-VB- drill cuttings and gas traces from the shale shakers, sidewall cores from the Schlumberger Sidewall CoreDriller tool, rock fragments from the drillpipe-conveyed cutting sampler and fluid samples collected during pump test and downhole. 

The field laboratory provided cataloging and storage facilities and a data base of basic information such as petrophysical properties, mineralogy and lithology needed for further experiments.

Nearly 400 logging runs were made in KTB-VB - the pilot hole- with every available borehole instrument. And 266 runs were made in KTB-HB- the superdeep hole. The wealth of data acquired in the field lab allowed a rare opportunity to calibrate borehole log responses to core data in crystalline rocks - as opposed to sedimentary environments where their response is well known- satisfying one of the main objectives of KTB-VB. 

The formations that were cored and drilled consisted of metamorphic basement rocks- principally gneisses and amphibolites. Initially cores and rock fragments - from cuttings- were photographed and cataloged according to depth recovered. Microscopic analysis of thin sections assisted recognition of mineralogy and microstructure and assignment of rock type. By mapping the macroscopic structure and orienting it with borehole logs such as the FMI Fullbore Formaiton MicroImager image or borehole Televiewer (BHTV) image, a structural picture of the borehole was gradually built up.

Petrophysical parameters , such as thermal conductivity , density, electrical conductivity, acoustic impedance, natural radioactivity, natural remanent magnetism and magnetic susceptiblity were also routinely measured. In addition to determining the strength of rock samples, scientists made highly sensitive measurements of expansion of the cores as they relaxed to atmospheric pressure.

Geochemists at the field laboratory performed detailed core analysis using X-ray fluorescence for rock chemical composition and X-ray diffraction for mineralogy. This analysis allowed a reliable reconstruction of the lithology.

After comparing logs with cores,scientists at the Geophysical Institute at the University  of Aachen were able to distinguish 32 distinct electrofacies corresponding to 32 minerals. This enabled borehole logs to contribute to and refine the lithological profile of the superdeep borehole, established from cutting samples and the limited cores available. 

One contributor to the success of the logging operation was the GLT Geochemical Logging Tool. This provided concentrations of 10 elements present in rock: silicon, calcium, iron, titanium, gadolinium, sulfur, aluminum, potassium, uranium and thorium. 

Another tool with a semiconductor detector - germanium- was also used, which gave a higher sensitivity and provided the additional elemental concentrations of sodium, magnesium, manganese, chromium and vanadium. By combining the GLT results with other measurements, minerals such as pyrite, pyrrhotite, magnetite and hematite could be quantified.

Older logging techniques also proved invaluable. Abnormal Spontaneous Potential (SP) deflections occured across mineralized fault systems. Other SP deflections combined with low mud resistivity readings from the Auxiliary Measurement Sonde (AMS) occured at zones of water influx. When the AMS resistivity showed only mud and the SP showed a deflection, this was regarded as an indicator for mineralization. Uranium tends to concentrate at graphite accumulations so the uranium reading from the NGS Natural Gamma Ray Spectrometry tool was used as a graphite indicator.

Although there are several standard high-temperature logging tools available, tools were upgraded especially for KTB. One example is the high-temperature Formation MicroScanner tool, which was upgraded to 260 degree. The first task in modifying this tool was to produce a list of components to upgrade. Several components, such as the pads containing the button electrodes, were not changed, but could be used only once. Other components, such as the hydraulic motor that opens and closes the sonde calipers, could still be used more than once. Mechanical maintenance of such high-temperature tools has to be meticulous- using even one component that should have been changed could result not only in malfunction but also in destruction of expensive equipment.

Temperature limits on the mechanical aspects of the tool were relatively straightforward to overcome. However, the electronics were of major concern. Normally these operate up to 175 degree C. To keep the temperature within this limit meant housing them inside a Dewar flask. The outside temperature could be as high as 260 degree C with the inside remaining below 175 degree C for up to 8 hours.

The cooling effects of mud circulation during drilling were calculated to be about 50 degree C at TD. When circulation stopped, the temperature would gradually climb, giving a window of 36 hours for logging before it exceeded tool ratings. On the first logging run at TD, the maximum temperature recorded was 240 degree C and on the last run , this reached 250.5 degree C- confirming earlier calculations. At the end of each logging run the Dewar flask were cooled down slowly by blowing air through to avoid thermal shock. 

Surprises- Some Welcome, Some Not

Both boreholes yielded unexpected results for the scientists. Geologist had formed a picture of the crust at the Windischechenbach site by examining rock outcrops and two-dimensional (2D) seismic measurements. At a depth of about 7000 m [22,966 ft] they had expected to drill through the boundary between two tectonic plates that collided 320 million years ago, forming the Euarasian plate. However, this boundary was never crossed, and the geologist have had to redraw most of the subsurface picture. 

Other unexpected results include core and log evidence for a network fo conductive pathways through highly resistive rock, and in rock devoid of matrix porosity, an ample supply of water. 

Seismic Investigations 

During the project, surface and borehole seismic measurements helped visualize the structure below the KTB site. The original picture had been formed from 2D seismic work undertaken before drilling. But the structural profile of KTB-VB showed a more complicated subsurface. Instead of a nappe unit, the formation followed a more tortuous path. 

After KTB-VB was completed in April 1989 , a year was spent on major seismic evaluation. The seismic work, under the joint responsibility of KTB and DEKORP - German Continental Reflection Seismic Profiling- was performed by Prakla-Seismos- now part of Geco-Prakla. This included a 3D survey over an area of 19 by 19 km , vertical seismic profile (VSP) and moving source profile (MSP), using geophones in KTB-VB, and two wide-angle 2D seismic surveys with an offset of 30 km using vibrators and explosives as sources. 

The evaluation, conducted by a number of German universities and their geophysical institutes, utilized acoustic impedance calculated from borehole sonic and density measurements and the acoustic measurements mad on cores in the field laboratory. 

The seismic processing was complicated by the tortuous structure and the large seismic anisotropy. The results, however, gave a much clearer picture than the earlier 2D work and accurately predicted the major fault system drilled through between 6850 to 7300 m.

It is known that the borehole remained inside the Zone of Erbendorf Vohenstrauss (ZEV) , a small crystalline unit tectonically placed between the Saxothuringian and Moldanubian units. There are indications that these metamorphic units of the Bohemian Massif have been uplifted 10 km since Variscan time - about 300 million years ago- and eroded to the present day surface.

Future experiments have been designed to measure seismic anisotropy at greater depths, the spatial extension of seismic reflectors- such as the "Erbendorf" structure at a depth of about 12 km - and the detailed velocity distribution between the two boreholes using seismic tomography. Seismologists will also take advantage of the superdeep borehole KTB-HB by recording downhole seismic waveforms emitted by earthquakes. In this way, surface noise will be reduced and the frequency content of the signal preserved.

Electromagnetics- One of the reasons for choosing the Windischeschenbach site was to investigate the origin and nature of a low resistivity layer recorded by surface measurements that appeared to be 10 km below the Earth's surface. This is not unique to southern Germany, as similar layers are found in many continents around the world. 

To unravel the mysteries of this conductive layer, scientists pursued many different angles. Conductivity measurements on cores from KTB-VB showed high resistivity as expected in crystalline rocks. But then highly conductive graphite-bearing faults and cataclastic zones at various depths up to 7000 m. These were also seen on borehole logs where abnormal SP deflections of more than 200 millivolts (mV) coincided with the graphite. Other logs, such induced polarization- where the decay of a voltage applied at a surface electrode is measured downhole- showed conductive pathways potentially formed by veins of graphite and/or sulfides. 

At much larger scale, when the KTB-HB was at a depth of 6013 m a dipole-dipole experiment was carried out. This consisted of using the casing from both holes to inject current into the formation. The resulting potential field was measured around the borehole. Any changes in potential indicated a connection of an electric conductor to one of the casing, supporting the theory for a conducting layer extending over a distance of several hundred meters. The results showed that the conducting layer coincided with graphite deposits in a north-south striking fault system- the Nottersdorf fault zone. The faults from this system crossed KTB-VB at about 250 m [820 ft] and KTB-HB at about 1500 m [4921 ft]. 

Further experiments are planned to investigate the depth, thickness, electrical anisotropy and source of the high conductivity layer still believed to be at 10 km.

Stress and Deformation

One of the goals of earth science is earthquake prediction, and ultimately reduction in earthquake risk. The physics of earthquakes requires an understanding of the movement of tectonic plates, the forces involved and role the crust plays in transmitting those forces. Many scientist think that the top 10 km of crust is brittle and carries most of the stress that moves the entire 100-km thick continental plates. They also believe that, with increasing depth, the crust becomes ductile and cannot support the stress. KTB research may help clarify the transition from brittle to ductile.

Preliminary work in two KTB boreholes has already determined the orientation of the local stress field. The four-arm caliper, resistivity imaging tools, such as the Formation MicroScanner tool , and acoustic imaging tools, such as the BHTV, were used to calculate the stress direction from analysis of two types of failure: shear failure of the borehole wall- called breakouts- and drilling-induced tensile failures. The former occur at an azimuth orthogonal to the orientation of the maximum horizontal stress. The latter are near-vertical fractures in the borehole wall in the direction of the maximum horizontal stress. These fractures were easily identifiable on the cores cut in the KTB-VB and were oriented using Formation MicroScanner and BHTV images. The maximum horizontal stress is oriented to N 150 degree +- 10 degree E from surface down to 6000 m. 

To obtain the stress magnitude, hydrofrac experiments were carried out in both boreholes at various depths in conjuction with geoscientist at the Universities of Bochum, and Karlsruhe, Germany and at Stanford University, California, USA. By fracturing the formation, the minimum and maximum principle stresses were determined.

These and earlier tests in KTB-VB confirmed that the strength of the rock was increasing with depth, supporting the theory that the upper crust is strong enough to carry most of the stress of tectonic movement. Very recently, a hydrofrac experiment was carried out at 9000 m [29,528 ft] and is being evaluated.

 Thermal Studies

Of the many processes occuring within the continental crust, most are temperature dependent. Mapping the temperature distribution and measuring heat production, heat flow and thermal conductivity are therefore a vital part of understanding these processes. During the initial temperature mapping, KTB-VB held the unwelcome surprise that the formation temperature gradient was highger than anticipated. The disappointing result meant that 300 degree celcius - the set limit of current technology- would be reached at about 10,000 m- much shallower than originally predicted.

Temperature measurements were carried out in the two boreholes during regular logging campaigns. These were used to estimate true formation temperature. The borehole is cooled during drilling, by up to 70 degree celcius in the deepest sections of KTB-HB. Formation temperature is obtained by recording several temperature profiles at preset time intervals as the hole heats up again and extrapolating these  profiles to infinite time on a logarithmic plot.

Each temperature profile was recorded during the first wireline logging run. This helped avoid another complication, disturbing the mud temperature profile by the logging tools. A wireline tool was even modified at KTB with the temperature sensor mounted on the bottom of the tool to provide the least disturbance and give the best possible result.

Temperature data provided an opportunity to measure heat production and conductivity. In addition, thermal conductivity measurements were carried out in the field laboratory on cores cut from the boreholes. From the NGS and Litho-Density data, heat produced by radioactive decay was calculated - for metabasites the results were 0.5 micro-Watts per cubic meter.

The final temperature profile has yet to be extrapolated from the data obtained so far. Experiments will continue to examine temperature distribution, heat production, heat flow and thermal conductivity.


The scientist at KTB expected deep cyrstalline rock to be bone dry, but to their surprise, water  influx occured at several depths from open fractures.

Sonic, Formation MicroScanner and BHTV data were used to detect the fractures. As fresh mud was  used for drilling, any saline water inflow would cause a decrease in mud resistivity. This could easily be seen from mud resistivity measurements made by the AMS tool. These zones were allowed to produce by dropping the mud level, enabling a fluid sample to be collected by a wireline-conveyed sampler run in combination with the AMS tool. Test showed the water had not leached down recently from surface. Further tests will be performed to ascertain the origin and composition and investigate fluid-rock interaction. 

During a two-month pumping test 275 m^3 [1730 bbl] of salt water were produced from an open fracture system at the bottom of KTB-VB. Further evidence showed the extent of the fluid network. During a produciton test at 6000 m in KTB-HB, the fluid level in KTB-VB dropped. When the 13 3/8-in. casing in KTB-HB was cemented, there was an increase in fluid level in KTB-VB. These two events confirmed hydraulic communication and allowed an estimate of permeability of the fracture system between the two boreholes.

Natural causes of fluid movement became apparent when pressure sensors deployed in KTB-VB rcorded changes in pressure due to earth tides caused by the gravitational pull of the moon.

Fluids play an important role in the chemical and physical processes in the Earth's crust, influencing mineral reactions, rheological properties of rocks and melting and crystallization processes. To aid further scientific research into these processes long-term pumping tests are planned between KTB-HB and KTB-VB to measure hydraulic communication, identify fluid pathways and collect additional fluid samples.

Tight Reservoir

Tight formations scattered throughout North America have the potential to produce not only gas (tight gas) but also crude oil (tight oil) (Law and Spencer, 1993; US EIA, 2011,2013). Such formations might be composed of shale sediments or sandstone sediments. In a conventional sandstone reservoir, the pores are interconnected so gas and oil can flow easily from the rock to a wellbore. In tight sandstones, the pores are smaller and are poorly connected by very narrow capillaries which results in low permeability. Tight gas and tight oil occur in sandstone sediments that have an effective permeability of <1 mD and in addition, application of typical fractionating techniques to oil from tight formations would show very little, if any, resin and asphaltene constituens. The majority of the crude oil is typically low-boiling paraffin constituents and aromatic constituents. 

Conventional crude oil
Medium-to-high API gravity
Low-to-medium sulfur content
Mobile in the reservoir 
High-permeability reservoir
Primary recovery
Secondary recovery
May use tertiary recovery when reservoir energy is depleted

Tight oil
High API gravity
Low-sulfur content 
Immobile in the reservoir
Low-to-zero permeability reservoir
Primary, secondary, and tertiary methods of recovery ineffective
Horizontal drilling into reservoir
Fracturing (typically multifracturing) to release reservoir fluids

These prior efforts have produced a wealth of knowledge regarding the geological description as well as technical options and challenges for development. Thus far, none of these efforts have produced a commercially viable business in the United States. There needs to be economically viable, socially acceptable, and environmentally responsible development solutions. 

Generally, unconventional tight oil and natural gas are found at considerable depths in sedimentary rock formations that area characterized by low permeability. While some of the tight oil plays produce oil directly from shales, tight oil resources are also produced from low-permeability siltstone formations, sandstone formations, and carbonate formations that occur in close association with a shale source rock. 

In the same manner as conventional natural gas and crude oil, natural gas in shale formations and in tight formations has, essentially, formed from the remains of plants, animals, and microorganisms that lived million of years ago.  

Though there are different theories on the origins of fossil fuels, the most widely accepted is that they are formed when organic matter (such as the remains of a plant or animal) is buried and compressed (even heated but the actual temperature of the maturation process remains unknown and, at best is only speculative) for geological long time (million of years). 

More specifically, natural gas and crude oil in shale formations and in tight formations are generated in two different ways: (1) as a thermogenic product that is generated thermally from the organic matter in the matrix and (2) as a biogenic product - an example is the Antrim shale gas field in Michigan in which the gas has been generated from microbes in areas of fresh water recharge (Martini et al., 1998, 2003).

By way o of explanation, the origin of natural gas and crude oil is an important aspect of evaluating shale reservoir. For example, thermogenic systems often produce natural gas liquids with the methane, which can add value to production, whereas biogenic systems typically generate methane only. Thermogenic systems can also lead to the generation of carbon dioxide as an impurity in the natural gas, which must be removed during the gas processing operations. Also , reservoirs classed as having thermogenic origins tend to flow at high rates but are normally exploited through the extensive use of horizontal drilling and are therefore more expensive to develop than biogenic plays, which flow at lower rates and are exploited through shallow, closely spaced vertical wells instead.

Thus, the thermogenic product is associated with mature organic matter that has been subjected to relatively high temperature and pressure in order to generate hydrocarbons. Moreover, all other factors being equal the more mature organic matter should generate higher-gas-in-place resources than less mature organic matter (Martini et al., 1998).

However, generation of the gas and oil within individual shale formations and tight formations may differ significantly. Better knowledge is needed, for example, on basin modeling, petrophysical characterization, or gas flow in shales for an improved understanding of unconventional reservoirs. 

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


Thursday, October 17, 2019

Tight Gas chapter 2

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

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

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

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

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

On the other hand, shale gas is obtained from ultra-low permeability shale formations that may also be the source rock for other gas reservoirs. The natural gas volumes can be stored in fracture porosity, within the micropores of the shale itself, or adsorbed onto the shale.

To prevent the fractures from closing when the pressure is reduced several tons of sand or other proppant is pumped down the well and into the pressurized portion of the hole. When the fracturing occurs millions of sand grains are forced into the fractures. If enough sand grains are trapped in the fracture, it will be propped partially open when the pressure is reduced. This provides an improved permeability for the flow of gas to the well.

It has been estimated that there is on the order of 750 trillion cubic feet (Tcf, 1 x 10 ^12 ft^3) of technically recoverable shale gas resources in the United States and represents a large and very important share of the United States recoverable resource base and in addition, by 2035, approximately 46% of the natural gas supply of the United States will come from shale gas (EIA, 2011). 

Tight gas is a form of unconventional natural gas that is contained in a very low-permeability formation underground- usually hard rock or a sandstone or limestone formation that is unusually impermeable and nonporous (tight sand). In a conventional natural gas deposit, once drilled, the gas can usually be extracted quite readily and easily (Speight, 2007). Like shale gas reservoirs, tight gas reservoirs are generally defined as having low permeability (in many cases < 0.1 mD, Law and Spencer, 1993). 

Tight gas makes up a significant portion of the natural gas resource base -> 21% v/v of the total recoverable natural gas in the United States is in tight formations and represents an extremely important portion of natural gas resources.

In tight gas sands (low-porosity sandstones and carbonate reservoirs), gas is produced through wells and the gas arose from a source outside the reservoir and migrates into the reservoir over geological time. Some tight gas reservoirs have also been found to be sourced by underlying coal and shale formation source rocks, as appears to be the case in the basin-centered gas accumulations.

However, extracting gas from a tight formation requires more severe extraction methods- several such methods do exist that allow natural gas to be extracted , including hydraulic fracturing and acidizing. It has been projected that shale formations and tight formations containing natural gas and crude oil with a permeability as low as 1nD may be economically  productive with optimized spacing and completion of staged fractures to maximize yield with respect to cost (McKoy and Sams, 2007). In any case, with all unconventional natural gas and crude oil reserves, the economic incentive must be there to encourage companies to extract this gas and oil instead of more easily obtainable, conventional natural gas and crude oil.

Tuesday, October 15, 2019

Tight Gas

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

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

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

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

Thursday, October 3, 2019

Tight Oil chapter 5

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

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

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

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

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

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