OPEN HOLE GAS WELL CLOSED CYCLE DRILLING AND PRODUCTION SYSTEM WITHOUT GAS VENTING AND FLARING OR RESERVOIR DAMAGES

Abstract

An open-hole drilling method and process is embodied in creation of a closed cycle and system for extracting gas from shale and other impermeable and natural vertical fracture dominated reservoirs. The closed cycle system enables gas from reservoir to be used as a drilling fluid, with any excess gas produced as the wellbore is extended, to be sold in real time through a gas pipeline. Since only natural gas exists throughout the closed system, no risk exists for downhole explosions, and no wellbore damages occur from foreign fluids, such as mud, cement, and water. Limits of wellbore length due to gas produced while drilling, and risks during gas flaring are eliminated. All products produced from wellbore are captured so no venting of any liquids, gases, or solids. All hydraulic fracturing issues are avoided. Gas flow rate measurements while drilling enables technical, financial, reserve estimate models development in real time.

Description

CROSS-REFERENCE TO RELATED APPLICATION

“Not Applicable”

BACKGROUND OF THE INVENTION

The great gas and oil reserves discovered in the Marcellus Shale and the Utica Shale in the extended Appalachian Basin have generated tremendous efforts to recover these natural resources. Somewhat like other low porosity, low permeability oil and gas formations with huge reserves, these shales present recovery issues challenging to the most sophisticated in the industry. The Marcellus Shale is known for its hierarchical natural fracture networks and systems that largely constitute the reservoir, ranging from the nano scale to large macro scales of feet and miles. The most dominant macro scale fractures are visible not only in the shales, but also in outcrops throughout the world, and are widely known as “the natural vertical fracture systems”, or joints, which also extend vertically below 10,000′ and have a general trend of about N45° E in Appalachia. These vertical natural fracture systems are the primary conduit for oil and gas to migrate to the wellbores drilled in the shales, especially now for horizontal, directionally drilled wells. Recovery and success of wells drilled through these shales is so dependent upon them that wellbores are oriented so as to intersect the maximum number of them at large angles of the order of 90°, at N45° W. However, completing wells by stimulation, such as hydraulic fracturing, following drilling of the boreholes, such that the hierarchical fracture networks connect to and remain open sufficiently for drainage to the wellbores is the real challenge facing the industry. In essence, technologies that evolved throughout oil and gas extraction history for competent sandstones, limestone, and other hard rocks are being applied to the shales. This historic technology that involves over 8 major steps or phases of drilling, cementing pipe, perforating pipe, creating 100 or more of stages, setting plugs, hydraulic fracturing using 1,000's of barrels of sand laden water, drilling out plugs, and well cleanout, all requiring 1,000's of large truck trips of products is extremely time consuming, expensive, destructive to roads and the environment. The oil and gas industry is desperate for better extraction technology.

This inventor has created inventions leading to patents in this realm since 1974, and more recently this application is an outgrowth of one, U. S. application Ser. No. U.S. Provisional Patent application Ser. No. 61/650,259 filed on May 5, 2012, “Method of Further Fissuring a Natural Vertical Fracture System in order to Improve Connectivity between a Pay Zone of a Petroleum and natural Reservoir and a Horizontal Wellbore through a Sedimentary Stratum”, but was paused because a disclosure requirement for the “perturbation” claimed in the application would have given the methodology to the world, and would have been very difficult to enforce in deep wells underground anywhere, but especially in typically remote and inaccessible locations. This application includes the methodology in that application and much more. This application includes additional processes and methodologies that combine to achieve three distinctive effects, each of major consequence in the extraction and production of oil and gas. First, it may be observed that the methodology disclosed in this patent application is a one stage, or step, or phase process, as starkly contrasted to the classical extraction 8 phase, and over 100 stages process described above.

Beyond the huge issues in the major 8 phase and 100 stage process of cost, time consuming, hydraulic fracturing with huge volumes of products required, and damages to roads and the environment, the results are even unsatisfactory. It is an established fact that after nominally 2 years, the decline curves for Marcellus Shale wells drilled throughout the Appalachian Basin where the Marcellus exists, take a severe negative slope corresponding to about 80% decline from initial production. It is further more meaningful and disturbing when interpreted to mean that only about 7% to 20% of the original resources in place are being recovered. It is even more disturbing to know that all the methodologies used in the drilling and completion of these wells today, not only recover only 7% to 20%, but permanently seal off the majority of the all important natural fracture networks such that the remaining resources are “entombed” and never recoverable regardless of any future completion methodology, including classical secondary and tertiary concepts. This constitutes a U. S. National security issue pertaining to long-term recovery of our National energy reserves, as well as, a devastating impact on the mineral owner(s), that the remaining 80% to 93% of their minerals are forever lost. Since these same recovery technologies are used world wide, it also constitutes a permanent loss of more than 50% of the world's oil and gas resources used for energy and all the petrochemical based products enjoyed by humans. These phenomena are a result of what is called “formation damage”. The rest of the story is that other major low permeability reservoirs in the U. S., and perhaps other parts of the world, also exhibit this rapid 80% decline after two years or less of production because the same methodology is applied to all reservoirs around the world. These phenomena contain some very important messages. First, the present technologies and methodologies must immediately change! Second, the mechanisms contributing to these phenomena must be identified, characterized, and avoided in future methodologies, which is the essence of this patent application. There are four readily identifiable formation damage mechanisms. The first is a result of using drilling mud in the drilling process, which carries the drill cuttings back to the top of the ground for disposal, and is also beneficial in well control, borehole stability, etc. However, the negatives greatly outweigh the positives, since this mud with the thousands of psi hydrostatic pressure plugs off the only major conduits of hierarchical natural fracture networks, being the main conduits to the wellbore, for perhaps 100's of feet away from the wellbore.

The second mechanism is that when the mud is flushed from the wellbore and pipe is run into the wellbore to be cemented back 7,500' as in the Marcellus Shale to the surface, the extreme hydrostatic pressures of 3,500 psi plus pumping pressures exceeding 4,000 psi on the cement further opens and penetrates the main natural vertical fracture conduits and permanently seals the hierarchical natural fracture networks, again radiating far out into the reservoir, such that the cementing and hydraulic fracturing process leaves about 50% to 80% of the reservoir “entombed” in blocks, and never to be recovered. The third and fourth mechanisms of reservoir damage occur during the hydraulic fracturing process of this shale with problematic mechanical properties. These damaging mechanisms are in addition to the multiple water effects and other negatives. Again, these phenomena are believed by this inventor to be the same problem that also occurs in many other oil and gas reservoirs in the world, based upon their symptomatic similar rapid decline curves in the second year. During fracturing, the in situ stress field adjacent and far remote from the wellbore is modified in such wanner as illustrated in the Shuck U. S. Pat. No. 4,005,750, Feb. 1, 1977, “Method for Selectively Orienting Induced Fractures in Subterranean Earth Formations”. Due to the low mechanical ultimate compressive and shear strengths of the shale being exceeded during this process, a 3-D cage or shield of failure damage occurs that destroys the otherwise communicating hierarchical network of frqctures. This formation damage mechanism is not reported in the literature. The fourth mechanism is actually a phenomena associated with: a) the earth's in situ stress field and differences in maximum and minimum principal stresses, b) natural vertical fractures and the stress concentration factors at the tip of a propagating fracture as in fracture mechanics, c) the fabric of the fractured network, and d) the nature of the design process of perforating steel pipe to hydraulically fracture the reservoir rocks. The culmination of effects of these four mechanisms is that once an induced hydraulic fracture intersects a natural vertical fracture, it will follow it extensively, in two directions in an upward manner until conditions for propagating a new orthogonal set of fractures evolve. There are also other multiple mechanisms documented in the literature, beginning with the drilling process, that tend to plug off the natural fracture networks. The exact magnitudes of their impact are not precisely documented. These mechanisms have led to various methods of controlling the downhole pressures, such as, underbalanced, managed pressures, etc. The Marcellus Shale is also known throughout the history of drilling deep wells below the Marcellus to be a problem zone. This is because it often presents a high risk of getting the drilling tools “stuck in the hole” and can lead to loss of the well. The detailed mechanisms by which this occurs have never been quantified in an engineering manner or at least reported as such in the literature to this inventor's knowledge. However, it is known that usually drilling to reach rock formations below the Marcellus is done by drilling on air down to within a couple hundred feet above the Marcellus and then “mudding up”, by using drilling mud (much as today in drilling within the Marcellus) to drill and complete wells for any purpose below the Marcellus, as a means of not getting drilling tools stuck in the hole.

Thus, there is much to be concerned about in extracting oil and gas reserves from all types of reservoirs around the world, in addition to the profound and well documented reservoir damage and 80% decline curves that must be avoided if at all possible in drilling through or within the Marcellus and other Shales, and other sensitive property earthen substances. There are also many issues associated with water usage, sources, transportation, and disposal in addition to formation damage. Gas flaring and general venting anything from the wellbore into the atmosphere are issues that have gained National public and Government attention and President Obama and the U. S. Environmental Protection Agency advocated and almost implemented regulations that everything coming out the top of an oil or gas well must be captured and not vented to the atmosphere. If this had been strictly enforced, it would have eliminated all oil and gas well drilling because the technologies did not exist to accomplish the zero emissions. Therefore, a real urgency exists and time is of the essence. This invention is actually a breakthrough effort and process. This method and process constitutes an achievement advocated by the U. S. Government over ten years ago, and could prevent future shutting down drilling of all oil and gas wells in the United States. Thus, this can be a transformational milestone methodology and process.

This closed cycle system and process is designed to be implemented only for the horizontal lateral wellbore that begins at the precipice of the pay zone of interest, in this example case, the Marcellus Shale. This system and process is not limited to the Marcellus Shale, and can be applied to any oil or gas pay zone of interest at any depth, whether or not a shale rock formation. In applying this system and process, the vertical well with all of the conventional protective strings of vertical pipe, typically three, are cemented into place as usual. This vertical well can stop at a distance of typically 500′ above the bottom of the pay zone of interest in such manner that the 500′ radius curve to get 90° from vertical is then drilled down to and through the Shale and left open hole. More typically, the vertical well will be drilled on around the curve through the Marcellus Shale, such that when the 90° horizontal point is reached, it is also at the desired depth starting point within the Shale where the lateral will begin to be drilled, often in a 75′ thick pay zone about 20′ up from the bottom of the pay zone. Thus, the last string of pipe is inserted beyond the vertical point all the way around the curve, called the heel, and then cement is circulated from the bottom of the steel pipe at the bottom of the curve all the way up the annulus to the top of the ground. In this manner, the horizontal lateral actually begins at the end of the steel pipe which is located at the tangent point when the curve just becomes horizontal. The 500′ radius allows the steel pipe to be sufficiently bent to go around the curve. This assures that no gas will leak by the pipe out of the pay zone interval. At this time a substantial seal exists down to the end of the steel pipe. The drilling tools can also negotiate this 500′ radius within the steel pipe and at the horizontal point begin to drill the lateral after the total system is flushed, scavenged and purged of all gases or liquids that may remain following the cementing of the last string of pipe, and pressure tested with only natural gas throughout the system.

BRIEF SUMMARY OF THE INVENTION

The closed cycle system illustrated in FIG. 1 functions in the following simplified manner. Natural gas is purchased by opening master valve A1 which is connected to a gas sales and purchasing master meter A2, which is then connected to a gas purchasing and sales pipeline A3, whereupon gas, flows through pipeline (A1 to C1) and compressed by C1 to scavenge, purge, pressurize and pressure test the entire system piping network, starting with B and cycling through C2, E, F, G, H and pipelines (H to A), and (G to B). Following startup safety and operational protocols, gas circulation begins, the drill bit encounters the pay zone with prescribed bit pressure, and drilling begins and continues to final length. All pipes and connections in this closed cycle are conventional high pressure pipes rated above 10,000 psi and typically connected and sealed with conventional hammer unions and not disconnected during entire process. During the lateral drilling process additional pipe joints are added using a hydraulic type fitting with O-ring type seals that prevent pressure loss during added joints makeup and drilling. When gas produced by the well while drilling exceeds that required for drilling, the excess gas, instead of being flared conventionally, is cycled back through the F, G and H system shown in FIG. 1, and then passes back through a master valve A1 and gas master flow meter A2 into a gas sales pipeline A3.

Most issues discussed in Background above are circumvented by this comprehensive closed cycle system which constitutes a one-step or one-phase process when compared to conventional drilling, cementing pipe, perforating, fracking, and well clean up taking several weeks prior to selling gas into a pipeline.

BRIEF DESCRIPTION OF THE DRAWINGS

The aforementioned and other aspects, features and advantages can be more readily understood from the following detailed description with reference to the accompanying drawings wherein:

FIG. 1 shows the major components and functionality of this closed cycle system are illustrated.

DETAILED DESCRIPTION OF THE INVENTION

Basic Closed Cycle System Functionality

The closed cycle system illustrated in FIG. 1 functions in the following simplified manner. Natural gas is purchased by opening master valve A1 which is connected to a gas sales and purchasing master meter A2, which is then connected to a gas purchasing and sales pipeline A3, whereupon gas, flows through pipeline (A1 to C1) and compressed by C1 to scavenge, purge, pressurize and pressure test the entire system piping network, starting with B and cycling through C2, E, F, G, H and pipelines (H to A), and (G to B). Following startup safety and operational protocols, gas circulation begins, the drill bit encounters the pay zone with prescribed bit pressure, and drilling begins and continues to final length. All pipes and connections in this closed cycle are conventional high pressure pipes rated above 10,000 psi and typically connected and sealed with conventional hammer unions and not disconnected during entire process. During the lateral drilling process additional pipe joints are added using a hydraulic type fitting with O-ring type seals that prevent pressure loss during added joints makeup and drilling. When gas produced by the well while drilling exceeds that required for drilling, the excess gas, instead of being flared conventionally, is cycled back through the F, G and H system shown in FIG. 1, and then passes back through a master valve A1 and gas master flow meter A2 into a gas sales pipeline A3.

This basic closed cycle system, one-phase process, and simultaneous combined drilling and well-completion methodology incorporate subsystems that create versatility, features, and results also unique to the industry. The methodology is described first.

Methodology

For many reasons described above under Background that are distinctly different from this herein methodology, it is hereby made a part of this Specification. It is of paramount importance to use in the drilling process through a friable and sensitive rock formation, such as the Marcellus and other Shales, a drilling fluid that does not damage in any way the ability for gas to flow from the rock, it's matrix or natural fracture network system, into a penetrating wellbore. Thus, the minimum restriction of an uncased borehole without steel pipe cemented in, or any sleeves is a fundamental condition and objective of this methodology. This is known as an “open-hole” well completion method. The various unique embodiments of this methodology include:

1. The natural gas drilling fluid used is in a gaseous thermodynamic state, without presence of any oxygen or water molecules. Since no air, drilling mud, cement, or any other oxygen containing compound is introduced into the wellbore during or after drilling, this method uniquely constitutes both an oxygen-free drilling, and well-completion method and process. The hypoxia or anaerobic down-hole environment thusly created entirely eliminates the risk and preventative measures normally taken for downhole explosions.

2. The drilling fluid is a hydrocarbon of the same general chemical composition as the native fluid stored in the rock formation, known as natural gas, which may have innumerable hydrocarbons, all combustible or explosive when combined with oxygen under various conditions. However, this fluid being reintroduced to the rock faces does not in any manner damage the ability of the rock to allow gas to flow into the wellbore.

This is in stark contrast to use of water with viscosity and surface tension plugging small fractures and prohibiting gas tlow.

3. This unique method utilizes the native fluid of natural gas from the gas reservoir as the drilling fluid, starting from the beginning of the drilling process and rapidly increasing to 100% after the priming natural gas of essentially the same composition obtained from the gas sales pipeline is displaced and returned to the gas sales pipeline from which it was obtained. In essence, the startup priming natural gas from the sales pipeline is just “borrowed” for a very short period and quickly returned to the sales pipeline from which it was obtained. This method has never been used, and is a dramatic and unprecedented achievement.

4. The rapidity with which the borrowed priming natural gas is displaced and replaced as the drilling fluid occurs in dramatic steps, typically every 3′ to 10′ of borehole drilled, as each natural vertical fracture is intersected. This is a result of the Marcellus and other Shales having nano order of matrix permeability, while the vertical fractures, the main conduits to the wellbore, have permeabilities of 3 to 6 or higher orders of ten magnitude of permeability. This rapid entry of gas from the fractured reservoir into the wellbore largely constitutes “excess” gas that would normally be vented to the atmosphere or flared in exiting the above ground piping annulus. In this unique, unprecedented method, this gas is returned to the sales pipeline on a continuous, steady basis.

5. Ordinarily, gas sales pipelines laid to the pad and connected in any way to any pipe connected to the drilled well are the last step in the drilling and completioiu process for a wide variety of reasons. However, in this method, laying a gas sales pipeline up to the pad, and connecting it to a drill pipe is one of the initial steps in this method and process.

6. This “selling-gas-while-drilling” method also enables other processes to be introduced, including:

a) The economic success of the well is measured continuously, every foot of wellbore drilled and every natural fracture intersected by the wellbore, because the gas is going through a sales gas meter, which can be remotely monitored either in an onsite van monitoring and control station, or over the internet. This means that economic algorithms can be used in real time every step of the way to calculate the value of reserves being recovered using existing reservoir models, which may also provide bases of when to stop drilling based upon any economic or risk models.

7. In fact, this methodology enables and allows for the first time, the real-time research task of creating new reservoir models for naturally fissured and fractured reservoirs and calibrating them based not only upon real gas flow quantities recovered, but all of the precise geological, natural gas and petroleum engineering conditions and data existing at the specific site to be input to the onsite computer system apriori to drilling, such that immediately after the well is drilled, RESERVES ESTIMATES for the ultimate production for the life of the well can be made available to investors and the users of technical data and models. This is again a monumental capability and achievement for the industry. Even just the basic calculations of reserves estimates are currently conventionally made days and months after the well is drilled. The real-time creation and calibration of such a model for fractured reservoirs over an extended period of time and by large funded research programs is a major objective of the industry today.

8. The fact that gas flow rates into the open wellbore are measured while drilling is a valuable research tool. This allows gas entry to be correlated with major natural fracture systems, and map them, their frequency, and major role assessment in reserves recovery models, all useful in creating engineering design plans for drilling and advancing technology in sensitive reservoirs. This enables creation of all types of models in real time ranging from process design to financial analysis to futuristic reserve recovery efficiency and total reserves to be recovered.

9. This selling-gas-while-drilling method also reduces the current methodology urgency and main objective to get the lateral borehole drilled ASAP, because the Rig cost of nominally $15,000/day is largely offset, since the excess gas being recovered while drilling is being sold. That is, drilling penetration rate can be as slow as needed without major financial penalty.

10. This selling-gas-while-drilling method also is in stark contrast to the current methodology limitation of having to stop drilling and remove the drilling tools from the wellbore under risky conditions, when drilling on air or other gases or liquids, and the volumes of natural gas being produced greatly increase risk of down-hole explosions, or can no longer be safely flared or handled by the equipment and well-control risks are too high. In this method, many such issues are averted, and the length of borehole that can be drilled is greatly increased.

11. This selling-gas-while-drilling methodology enables the currently feasible length of drilled laterals to be extended by 1,000's of feet, and only limited when a variety of other parameters or variables become the limiting factors. That is the extra gas entering following each natural vertical fracture intersected does not become an untenable or unmanageable problem. On the contrary it is immediately an asset.

12. This methodology also embodies a “start-stop-forward-and reverse-drill cycle” (FRDC). The friable, fissured shales are highly likely to shear or drop slivers or blocks of shale into the drilled wellbore. These droppings are usually referred to as “wellbore stability” issues, which can cause high torque on the drill collars or drill bit assembly and the entire drill pipe to get stuck and potential loss of the well. Thus, this FRDC can be enabled and utilized at any point or time deemed desirable in the entire wellbore drilling process. A conventional reaming type tool is assembled behind the main drill bit in such manner that when forward drilling or reverse retrieving the drill pipe while still rotating, the reaming tool will crush the droppings into fine particles that can be circulated to above ground facilities along with all other cuttings. Several variables, such as drill pipe torque, reduction in steady flow of cuttings, downhole pressures, volumes of gas being produced, etc. can be used for decision making to determine two characteristics of the FRDC process, namely a) the stroke amplitude of the FRDC, and the frequency of utilization of the FRDC. Once again, while rig cost is a decision making parameter, these other downhole parameters also become strong variables in the decision making of the drilling engineer. This FRDC can also be considered a safety factor to be used frequently to avert risk of getting tools stuck in the wellbore.

13. This FRDC also is a process that functions without needing to know the unknown shale mechanical properties of moduli, such as the classical Young's Modulus, shear and bulk moduli, defined and used for conventional elastic, isotropic, and homogeneous material properties. When the in situ stress field of 1,000's psi is removed in creating the open borehole, the shale expands in all three dimensions in response to the three different magnitudes of in situ stresses along the borehole. This expansion in 3-D has various implications, one of them being the radial expansion toward the centerline of the borehole axis. This radial expansion will result in a reduction of wellbore diameter in real time while drilling, which will likely also contribute in various ways to the resulting named wellbore instability issue. This FRDC process allows this to happen in a less catastrophic and controlled or managed manner. That is, in contrast just to taking the bit to the reservoir rock and drilling the borehole forcibly and aggressively at maximum speed, this FRDC allows the reservoir rock to come to the bit in a controlled-managed manner. This method and process does not require any advance knowledge of the relative magnitudes of the horizontal-bedding plane in situ stresses or their differences, or the material mechanical properties. The FRDC method and process deals with these many possible mechanisms and above mentioned unknown material properties and behaviors of this fissured material in such a manner they are to a significant degree ameliorated by the FRDC.

14. This FRDC is the sub-process that is enabled by the closed cycle system, process and methodology, which constitutes both a combined “drilling” and “well-completion” process, which is always a separate and distinctly different process in all oil and gas well drilling operations today. This FRDC is in stark contrast to the hydraulic fracturing completion method and process used almost exclusively today, which creates traumatic borehole damages, and actually entombs and honeycombs with cement a high percent of the resources in place, perhaps greater than 60 or 70% that can never be recovered by any economic or technically feasible process.

15. Although one of the principal applications of this extraction process is solving problems for low permeability shales, it is actually independent of, and not a function of many of the mechanical properties of the reservoir rocks, and likewise independent of the state of in situ stresses of the reservoir. Therefore, it is applicable to any type of reservoir rock or it's in situ conditions. Current methodology today requires calculations that involve such mechanical properties as Young's modulus, compressive and shear ultimate strengths and elastic ranges, bulk modulus, fracture network characterization, in situ stresses, etc. These properties are incapable of being determined or even estimated in some cases. Since this method and-process do not utilize the properties in engineering design calculations, it is an extremely important feature of this method, system, and process. There are no completion steps, like hydraulic fracturing, staging, or fracture propping wherein such properties are used.

The Closed Cycle System

In this unprecedented single step or phase gas well drilling and production strategy and process, specially designed components allow the creation of a closed system, and closed cycle in which the same gas or gas just previously allowed to flow into the borehole is cycled back down the drill pipe after extracting all significant particles to continue drilling in a continuous, cyclic manner. Since this is a continuous process until the planned end of the horizontal lateral borehole is reached, it is truly a one-step or one-phase process. This achievement is believed to be truly transformational with huge potential for the oil and gas extraction industry around the world. This closed cycle system, comprised of the illustrated components, functions as a single entity in unison, such as a device or machine with single global purpose accomplishing a plethora of functions, and whcrein the two basic remaining conventional phases of drilling and well-completion are achieved simultaneously in one phase. This closed cycle system, wherein excess liberated gas beyond that required for drilling is disposed of by sending it back to a gas purchasing pipeline, enables the wellbore to be drilled to lengths dependent upon such variables as, strength of steel pipe, not quantities of gas produced from fractures that has to be flared in a wasteful and dangerous manner.

Larger Particles Separator

As the particle laden gas stream exits the tee connected to the annulus between the production string of pipe and drill pipe, it all passes through a large, high pressure vessel selected to separate the larger particles using centrifugal and gravitational forces, shapes, and geometrical configurations to separate the bulk of the particles from the turbulent gas stream. Vibrators may be strategically placed on the exterior walls of the separator to expedite particle collection at bottom of separator and mitigate side-wall sticking. The particles settle in a collector pipe at the bottom of the pressure vessel and entrance to a large ball-type valve with full throat opening and closing at 90 degree rotational intervals. This valve opens to a depressurization chamber of such size and volume to contain the particles during a pressure release period, which is cycled to dump the particles into an atmospheric pressure chamber collector for disposal. This is accomplished by a second ball valve on the bottom of the depressurization temporary storage-depressurization chamber. This emptying cycle period is computer controlled based upon transducers located on the separator.

Smallcr Particles Separator-Filter Sub-System

The characteristics of the particles suspended in the particle-gas stream at this point will vary with several variables associated with the drilling process and the fabric of the shale being drilled. A variety of commercially available separators and filters are used in a cascade manner in this system component. The fine particles are removed to whatever specifications

as may be required by various types of compressors, and as may be required by different pipeline companies to assure the excess gas stream meets gas sales pipeline quality standards. Appropriate modifications to these subsystems include the same provisions of vibration, collection, depressurization chamber with two isolation ball valves and atmospheric pressure collection vessel for particle disposal as in the larger particle separator.

Compressors

Two compressors illustrated in FIG. 1 as C1 and C2 meet the principal gas compression requirements for the closed cycle system. Since the process begins with thoroughly scavenging and purging the entire system of all existing gases, and then pressurization of the entire system for leak detection, followed by drilling initiation, the two distinct compressors are prescribed to serve these specific needs. The C1 compressor is a high-pressure low-volume-rate compressor, since time or rate are not of the same order as for C2.

That is, C1 can accept gas at whatever rate the gas sales pipeline can deliver at whatever pressure, and compress it to the desired pressure established for the surge-storage tank reservoir during whatever time is reasonably required. The requirements of C2 are similar in size and volume rate capacity to commercial compressors conventionally used for air drilling of wellbores. These rates for compressing the natural gas drilling stream are not of significant difference. There is one more compressor C3 not illustrated in FIG. 1, because it may or may not be needed as a required component to the basic closed cycle system. C3 will be designed and installed in the system on an “as needed” basis, which is contingent upon different drill site conditions, including the sales pipeline operating pressure. The sales pipeline rate capacity for accepting gas would obviously be capable of handling any excess volume produced during drilling or routine well production, or it would not have been laid to the drill pad in the first place. Thus, C3 specifications are, in general, lower pressure and lower flow-rate than C2, and lower pressure, but higher rate than C1.

Claims

1. A closed loop system for natural gas extraction, the system comprising:

an external gas pipeline;

a master meter valve, wherein the master meter valve supplies natural gas to the system, the supplied natural gas is obtained from the external gas pipeline;

one or more of a first compressor, wherein the natural gas supplied from the master meter valve flows to the first compressor so to increase gas pressure;

a surge and storage tank reservoir, wherein once a desired pressure is reached, the pressurized natural gas flows from the first compressor and system to the surge and storage tank reservoir;

one or more of a second natural gas compressor which receive natural gas when needed from the surge and storage reservoir so to deliver gas at rates and pressures required for drilling processes;

a well site, including a vertical well and a drill rig;

the drill rig further comprising a drill bit which is actuated by the pressurized natural gas fluid received from within the system or by a rotating drill pipe;

a particle separator for separating large particle cuttings from gas circulating fluid received from the well site;

a filter subsystem for removing smaller particles the gas circulating fluid received after being processed by the particle separator;

a natural gas stream conditioner for preparing the natural gas suitable to enter the external gas pipeline;

wherein once the natural gas is processed by the filter subsystem, the processed natural gas is dispersed between the natural gas stream conditioner and reentry into the system at the storage and surge tank reservoir as needed.

2. The system as claimed in claim 1, the system further comprising:

wherein the system is closed and sealed so that no substances other than natural gas are entered, exited or circulated within.

3. The system as claimed in claim 1, the system further comprising:

wherein the system is closed and sealed so that no substances are vented into the atmosphere.

4. The system as claimed in claim 1, the system further comprising:

wherein a primer quantity of natural gas is obtained from the external gas pipeline.

5. The system as claimed in claim 4, the system further comprising:

wherein after being primed, the pressurized natural gas fluid is obtained from the same gas reservoir borehole as the one being drilled.

6. The system as claimed in claim 1, the system further comprising:

wherein the system does not use any of drilling mud, cementing pipe through the pay zone, perforating pipe and hydraulic fracturing.

7. A method using a closed loop system for natural gas extraction, the method comprising:

obtaining natural gas from an external gas pipeline;

supplying natural gas to the system from a master meter valve;

receive the flow of natural gas from the master meter valve at one or more of a first compressors;

increase gas pressure using the one or more of a first compressors to a desired pressure within the system;

wherein the pressurized natural gas flows from the first compressor and system to a surge and storage tank reservoir;

when needed, receive natural gas at one or more of a second natural gas compressors from the surge and storage reservoir so to deliver gas at rates and pressures required for drilling processes;

actuating a drill bit of a drill rig using a vertical well at a well site using the pressurized natural gas fluid received from within the system or actuating a drill bit by a rotating string of drill pipe;

separating large particle cuttings from gas circulating fluid received from the well site at a particle separator;

removing smaller particles from the gas circulating fluid received after being processed by the particle separator at a filter subsystem;

preparing the natural gas to enter the external gas pipeline at a natural gas stream conditioner;

wherein once the natural gas is processed by the filter subsystem, the processed natural gas is dispersed between the natural gas stream conditioner and reentry into the system at the storage and surge tank reservoir as needed.

8. The method as claimed in claim 7, the method further comprising;

a process of completion that does not involve the injection of any substance into the reservoir rock.

9. The method as claimed in claim 7, the method further comprising:

wherein the natural gas produced and processed from the well site being drilled is recycled back into the system as drilling fluid through the system.

10. The method as claimed in claim 9, the method further comprising:

the obtained natural gas from the external pipeline is used to prime the system, once the system is primed, the system then switches to used recycled natural gas.

11. The method as claimed in claim 7, the method further comprising:

a drilling process;

wherein the drilling process comprises: reaming a borehole while drilling a directionally controlled pilot hole by forward and reverse cycles, wherein the cycles are determined manually, periodically, or based upon measured variables values to achieve at least one of a plurality of objectives, the objectives comprising: a) cleaning the borehole of larger particles and crushing larger chunks suitable for gas stream entrainment and circulation to above ground facilities, b) enlarging the diameter of a borehole, and c) removing the damaged surface due to the front end drill bit.

12. The system as claimed in claim 1, the system further comprising:

wherein the excess natural gas produced beyond that required for drilling is cycled back through the system and out to the master meter valve, wherein the master meter valve supplies natural gas back to a master sales meter and the external gas sales pipeline.

13. The method as claimed in claim 7, the method further comprising:

wherein the excess natural gas produced beyond that required for drilling is cycled back through the system and out to the master meter valve, wherein the master meter valve supplies natural gas back to a master sales meter and the external gas sales pipeline.

14. The system as claimed in claim 1, the system further comprising:

wherein the system is hypoxia or anaerobic oxygen-free such that no internal system explosions can occur.

15. The system as claimed In claim 1, the system further comprising:

wherein after the conventionally drilled vertical well is drilled and completed, the system does not use any water on the drill pad, so to eliminate the risks of spills, prevent environmental violations, and prevent environmental damage to any adjacent water, ponds, creeks, streams, or rivers.

16. The method as claimed in claim 7, the method further comprising:

wherein after the conventionally drilled vertical well is drilled and completed, water is not used on the drill pad, so as to eliminate the risks of spills, prevent environmental violations, and prevent environmental damage to any adjacent water, ponds, creeks, streams, or rivers.

17. The method as claimed in claim 7, the method further comprising:

wherein a closed cycle extraction process is independent of mechanical properties of reservoir rock or its states of in situ stress field.

18. The system as claimed in claim 1, the system further comprising:

real time gas flow rate data from a master flow meter, which are used in real time to create computer models including reserve estimates.

19. The method as claimed in claim 7, the method further comprising:

calculating reserve estimates, by using real time gas flow rate data in conjunction with the real time created computer models.

20. The system as claimed in claim 1, the system further comprising:

wherein a length of drilled borehole that can be drilled is not limited as a result of an amount of gas liberated into a wellbore while drilling, when using the pressurized natural gas fluid as a drilling fluid, because quantities of the amount of gas liberated into a wellbore while drilling is unsafe and too great of a quantity to be flared.