Oil & Gas | Multiple Choices

Sec-A ( 5 Marks each=Total 20 Marks)

a. Write short notes on EOR and IOR

b. Define with example,

i. Bubble Point Pressure

ii. Formation Volume Factor

c. Define with Example.

i. Octane Number

ii. Cetane Number

d. How the Blow out happens in an oil Rig? How to prevent it?

e. What is the role of a Petrophysicist through-out the Life cycle of a Reservoir?

Sec B- ( 10 Marks each-Total 30 Marks)

a. Describe the types of drilling rigs in Off-Shore drilling.

b. Describe the Dunham's Classification in a carbonate reservoir.

c. Describe the phenomenon of " Migration" in an oil and Gas reservoir.

Sec C-(25 Marks each-Total-50 Marks)

There are two Technical papers attached herewith with relevant questions associated with them. Answer both the papers.

A.Tech Paper-1

B. Tech Paper-2

Case-1 Technical Paper-1

TRENDS IN UNCONVENTIONAL GAS RESOURCES

ADVANCE IN FRAC AND FLUID TO IMPROVE

TIGHT GAS PRODUCTION

ABSTRACT:

Only 10 years ago, unconventional gas was an emerging resource; now it's a core business of many large independent producers and growing number of major operating companies. Unconventional gas reservoir is a term commonly used to refer to a low permeability reservoir that produces mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low-permeability carbonates, shales, and coal bed methane. Normally, a large hydraulic fracture treatment is used to achieve successful stimulation. In some naturally fractured unconventional gas reservoirs, horizontal wells can be drilled, but many of these wells also need to be stimulated with hydraulic fracturing methods. This paper deals with the techniques involved in producing the tight gas from the reservoir with major emphasis on hydraulic fracturing and SurgiFrac.

INTRODUCTION:

Natural gas is formed over thousands of years by the combination of pressure and heat on organic material trapped in rock. After natural gas is formed, the earth's pressure often pushes the gas upward through small holes and cracks in rock until it reaches a layer of impermeable rock where the gas becomes trapped. It sits there in a "pool" until it is released from the ground by a drill bit providing a path to the surface. This is called as conventional gas, but there are gases which are held in Tight reservoirs where the permeability for the gas reservoir rocks are so low that the gas molecules cannot flow into the production well without any help these type of gases are known as unconventional gas resources which are the hot topic of research in recent years

These include:

• Tight Sands Gas – formed in sandstone or carbonate (called tight gas sands) with low permeability which prevents the gas from flowing naturally.

• Coalbed Methane (CBM) – formed in coal deposits and adsorbed 4 by coal particles.

• Shale Gas – formed in fine-grained shale rock (called gas shales) with low permeability in which gas has been adsorbed by clay particles or is held within minute pores and micro fractures.

• Methane Hydrates – a crystalline combination of natural gas and water, formed at low temperature and high pressure in places such as under the oceans and permafrost. The tight reservoir rocks tends to me much older many of them are of the Paleozoic era and typically lack the thick layers of porous and permeable sands that characterize the reservoirs in the younger tertiary basin such as the North Sea and Gulf Of Mexico .Any porosity and permeability they posses are lost due to compaction cementation recrystallization and chemical changes during their long and complex burial histories in unconventional gas permeability typically ranges from 0.01 to0.5 Darcy but in tight gas reservoirs permeability can be as low as fraction of a millidarcy even in microdarcy ranges . As a result many more wells are to be drained a tight gas field because each well produces a relatively small amount of gas .in addition the as should be connected with as much reservoir as possible so they often have a very complex geometries. They may for example drilled on a deviated path to bypass obstacles; or they can be horizontal; or multilateral, where several horizontal wells are drilled in a different direction originating from a single vertical well.

Hydraulic fracturing

Unconventional (tight), continuous type reservoir are not well suited for conventional formation evaluation. Pay zones frequently consist only of thinly laminated intervals of sandstone, silt, shale stringers, and disseminated clay. Potential producing intervals are commonly unrecognizable on well logs and thus are overlooked. To aid in the identification and selection of potential producing intervals, Hester developed a calibration system that empirically links the gas effect to gas production. The calibration system combines the effects of porosity, water saturation, and clay content into a single gas-production index that suggests the production potential of different rock types. The fundamental method for isolating the gas effect for calibration is the interpretation of a cross plot of neutron porosity minus density porosity vs. gamma-ray intensity. The geomechanical effect on reservoir performance should always be considered, especially when producing from thick formations or creating multiple fractures in horizontal wells. Recovering fracturing fluids is often difficult in under pressured, tight, deep formations. CO2, N2, and binary high quality foams are widely used in this type of reservoir because of their capacity to energize the fluid and improve total flow back volume and rate. Reducing gel volume decreases the amount of gel likely to be left behind in the propped fracture; the result is believed to be greater conductive fracture half-length. The foam fracture fluid is full of energy and begins to flow back to the surface readily when fracture pumping has ceased. The energized fluid is especially helpful in promoting frac-fluid flow back where formations are depleted and have lost significant pore pressure due to production. Surfactants designed to reduce surface and interfacial tension are also key elements in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation. Enhanced fluid recovery improves overall completion economics due to the lower total treatment cost and shorter time required for flowing back fluids. The most important benefit is achieving a less-damaged proppant pack, resulting in higher fracture conductivity.

Fracturing horizontal wells

Fracturing horizontal wells is the most promising production-enhancement technique in some formations. Fracturing in general is the more attractive completion option. It is even more attractive than multilateral completions, especially in tight, thick formations. In general, horizontal lateral wells have to be fractured to improve the economical outlook of the well. The geomechanical effect on reservoir performance should always be considered, especially when producing from thick formations or creating multiple fractures in horizontal wells. Hydraulic-fracture stimulation can improve the productivity of a well in a tight-gas reservoir because a long conductive fracture transforms the flow path natural gas must take to enter the wellbore. After a successful fracture stimulation treatment, natural gas enters the fracture from all points along it in a linear fashion. The highly conductive fracture transports the gas rapidly to the wellbore. Later, the gas in the reservoir is flowing toward an elliptical pressure sink and most of the gas enters near the tip of the fracture. The designing for hydraulic-fracture treatments for tight-gas sands suggests that successful stimulation requires creating long, conductive fractures filled with proppant opposite the pay zone interval. This is accomplished by pumping large volumes of proppant at high concentrations into the fractures, using fluids that can transport and uniformly distribute proppant deeply into the fracture.

SurgiFrac

Combined hydra jetting, fracturing, and jet-pump (CHF) technology is the first known successful method to resolve the problem of open hole fracture placement control by using dynamic diversion techniques. The technique (SurgiFrac) is a combination of three separate processes: hydra jetting, hydraulic fracturing (through tubing), and co injection down the annulus (using separate pumping equipment). One important aspect of this technique is the dynamic sealing capability. Unlike other techniques that require hardware-type packers or plugs, or even chemical plugs, this process essentially relies upon sealing by using fluid movement. Because packers are not used in most cases, the existence of passageways behind liner or through fractures rarely affects the performance of this process. The technique is based primarily on the Bernoulli principle, which states that the energy level of a fluid is generally maintained constant. To perform the SurgiFrac service, a jetting tool is placed near the toe of the well and used to jet perforate the casing and the formation rock, forming a 4-6-in. deep cavity. Based on the Bernoulli equation, as pressurized fluid exits the jetting tool the pressure energy is transformed into kinetic energy or velocity. Since the fluid velocity around the jet stream is at its greatest, pressure in this area is at its lowest, meaning the fluid does not tend to "leak" out somewhere. Conversely, fluid from the other areas of the well will flow into the jetted area. The fluid generally contains some abrasives to help the fluid penetrate the steel liner and the formation rock. As cavities are formed by each jet, high velocity fluid impacts the bottom of the cavity (e.g., velocity becomes zero, an energy change from kinetic back to potential energy or pressure), causing pressure inside the rock to become high enough to create a fracture. Annulus pressure is then increased to help extend the fracture. After the fracturing process is completed, the tool is moved to the next fracturing position and another fracture is placed.

The conversion of low-pressure, high-velocity kinetic energy to high pressure, low-velocity potential energy is extremely useful for fracture initiation and fracture placement. The breakdown pressure in a conventional treatment requires a tensile failure of the rock achieved by pressuring up the entire wellbore. Because, in most cases, fracture initiation pressure is much higher than fracture extension pressure, achieving multiple fracture initiation points along a horizontal wellbore requires achieving multiple fracture initiation pressures. This is very difficult in practice without some form of isolation along the wellbore. Since the energy of the jetting fluid is converted to pressure inside the eroded rock, the tensile failure of the rock occurs at the jetting point without exposing the wellbore to breakdown pressures. This enables precise control of the location of fracture initiation in the horizontal section. Multiple fractures can be created by simply moving the jetting tool to another location in the lateral and using hydra jet fracturing. Another attribute of the hydra jetting fracturing process is the creation of a dominant fracture through continued hydra jetting during fracture extension. As the fracture grows in width, the net pressure increase resulting from fracture extension induces stress normal to the direction of the fracture propagation; i.e reopening previous fractures becomes more difficult due to the increased stress induced by the dominant fracture.

The SurgiFrac service has been applied successfully in a variety of fracturing conditions:

• Multiple propped fractures in open hole.

• Multiple acid fractures in open hole.

• Deviated cased hole.

• Horizontal slotted liner.

• Coiled-tubing acid-frac to bypass damage.

• Multiple fractures in a cased horizontal wellbore.

A case history illustrates the utility of the multizone fracturing method. The first subsea CHF fracture stimulation was in 1,000 ft of water in Brazil's Campos basin. Because the stimulated well had two branches (abandoned due to drilling problems), it behaved like a triple lateral for stimulation design. The treatment resulted in five acid fractures, completed in 2.5 days.

Production rate for the first 15 production days following the treatment was almost double the maximum historical rate of this well and almost four times the monthly production rate during the months preceding the SurgiFrac.

Micro-emulsion surfactants

If the formation permits, often water-based hydraulic fracturing is carried out in tight gas formations. Traditionally, they have not been as optimally effective as they could be due to water blocking. A micro-emulsion surfactant (MS) has the potential vastly to increase the world's recoverable reserves of natural gas from tight-gas reservoirs by helping control fracture-face damage and boosting production from these difficult formations. The special surfactant was designed to replace methanol or conventional surfactants. Based on new micro emulsion technology (GasPerm 1000), the surfactant helps remove water drawn into the formation during the fracturing process. Desaturating water and removing phase trapping can improve inflow of gas from the fracture face and help increase gas production. Tight-gas reservoirs (as well as coalbed methane and shale formations) typically have low production due to low permeability and-or low reservoir pressures. The low permeability of these formations creates a capillary effect, in which water can be drawn or "imbibed" into these tight formations during fracturing treatment. The low reservoir pressures do not create enough flow for the gas to displace the liquid from the formation. Phase trapping can occur, in which the liquid becomes trapped within the low permeability formation at the fracture face, and the gas cannot displace it. This trapped liquid can inhibit production gas flows. Using a micro-emulsion surfactant can specifically mitigate fracture-face damage caused by capillary effects and phase trapping.

The surfactant can also enhance phase displacement and spatial flow behavior and help enhance mobility if liquid hydrocarbons are present.

This can help increase recoverable gas and improve well economics by:

1. Increasing actual production rates.

2. Increasing recoverable reserves.

3. Extending lifecycle of wells.

4. Shifting projects above the economic threshold.

The micro-emulsion additive is more effective at much lower concentrations than methanol, significantly reducing the volume required during fracturing treatment. It is a less flammable alternative to methanol-based fracturing fluids, thus improving safety and reducing environmental risk. The MS additive is compatible with both acidic and basic fluid systems and can be used as an acidizing additive or a fracturing fluid additive. The range of applications for this product continues to expand. MS service has been used in reservoirs with matrix gas permeability as low as the nanodarcy permeability range.

Two case studies illustrate the effectiveness of this technology:

• Ten horizontal shale wells in Oklahoma were recently completed with massive slick water fracturing. Four of these wells were fractured with MS service and six wells did not have the MS treatment. Using MS, early load recovery improved by 43%. The surfactant reduced water saturation and capillary pressures along the fracture faces, which improved relative permeability to gas. The wells treated with MS had initial gas production rates comparable to the best wells in the field.

• A Cotton Valley tight-gas sand in East Texas was fracture-stimulated with Micro-emulsion surfactant. The well produced more than 14 times the wellhead pressure (100 psi vs. 1,400 psi) and almost doubled the initial production rate (862 Mcfd vs. 1,432 Mcfd) compared to a conventionally treated offset well.

Refracturing

Hydraulic fracturing, especially in a horizontal well, is probably the best way to complete a well in a tight-gas formation. Fracture performance often declines with time, however. Reasons for performance degradation include:

• Loss of fracture conductivity near the wellbore due to embedment.

• Degradation of proppant with time and stress.

• Loss of fracture height with time.

• Loss of fracture length caused by degradation of proppant.

• Loss of fracture conductivity from fines migration.

• Loss of formation permeability near the fracture, forming a barrier.

• Entrapment of liquid around the fracture face by capillary force.

This effect may be aggravated by fluid loss during drilling and fracturing and by later movement of fines. This may be of special importance in tight-gas formations where a very high capillary pressure may be expected in cases having a water phase. Refracturing can expose more reservoir area to the high-conductivity fractures, thus improving well productivity and reservoir exploitation.

References

1. Kuuskraa, Vello A., "A Decade of Progress in Unconventional Gas," Advanced Resources International, Arlington,Va., July 6, 2007.

2. Tamayo, H.C., Lee, K.J., and Taylor, R.S., "Enhanced Aqueous Fracturing Fluid Recovery from Tight Gas Formations: Foamed CO2 Pre-Pad Fracturing Fluid and More Effective Surfactant Systems," paper CIPC 2007-112, CIPC 58th Annual Technical Meeting, Calgary, June 12-14, 2007.

3. Evans, Scot, and Cullick, Stan, "Improving Returns on Tight Gas," Oil and Gas Financial Journal, July 2007.

4. Hester, Timothy C., "Prediction of Gas Production Using Well Logs, Cretaceous of North-Central Montana," Mountain Geologist, Vol. 36, No. 2, pp. 85-98, April 1999.

ANNEXURE

Fig 1

Fig 2

Fig 3

Questions:-Answer all the questions

1. What is Shale Gas? Give a detail account of the Indian as well as the Global scenario with respect to the "Reserve" vis-a-vis the "Exploitation "of Shale gas.(2+4 Marks)

2.Mention Six varieties of Fracturing conditions where the "SurgiFrac" services has been applied successfully.(3 marks)

Write down the steps you follow before Stimulating a well. What is the role of a "Petrophysicist"in stimulating a well?(4 Marks)

3. Discuss the Hydraulic fracturing in a Horizontal well. Do you really need to fracture a horizontal well, when you are directly entering into a sweet zone for production optimization?(4 marks)

Give six reasons for degradation of fracture performance in a horizontal well.( 3 Marks)

4.Discuss the Gas production scenario(both historical and future projection ) of US dry gas from the Figure-2, cited in the assignment.(2marks).

Draw the rough sketch of the HBJ and Tripura gas pipeline in our country(3 marks)

Case-2 Assignment no-II

USE OF LASER TECHNOLOGY IN OIL AND GAS WELLS

Drilling an oil or gas well involves the integration of complex technologies. The well is the only conduit to move the oil or gas from the reservoir to the surface. And it must be a conduit that will last at least 50 years and be flexible enough in design to allow for the application of future technologies. To overcome the problems encountered is the biggest challenge during the drilling process and the primary reason for developing advanced drilling technologies. One of the advanced technologies is "Laser Technology".

Lasers can not only be used for drilling an oil and gas well but also for completion operations. Laser drilling has become well established as an economically viable method for producing sub-millimetre sized holes. This article reviews the basics of the laser drilling process and use of lasers for completion operations.

Laser technology applied to drilling and completion operations is attractive because of its potential to reduce drilling time. Lasers cut drilling time by not contacting the rock, eliminating the need to stop and replace a mechanical bit. When using laser technology for perforation, the rock is left cleaner, and fluid flow paths for oil and gas production are damaged less. Researchers believe that lasers have the potential to penetrate rock 10 to 100 times faster than conventional boring technologies and are a huge benefit in reducing the high costs of operating a drill rig. Other potential benefits of using a laser include the creation of a melted rock wellbore lining. This can eliminate the need for steel casing, and improve flow performance, if used as a perforator.

Origin

The earliest studies of laser drilling were in the 1960s and 1970s, but these were primarily theoretical. Physical tests by the laser technology were limited and low power was available at that time.

But then Gas Research Institute (GRI now the Gas Technology Institute) resurrected the idea of using lasers to drill oil and gas wells in 1997, when the institute initiated a two-year study to determine the feasibility of using the high power lasers developed by the U.S. military as part of the Reagan-era Star Wars Defense Initiative.

Those first steps investigated the interaction of lasers with different rock lithologies as the first step toward determining the energy required to remove rock with laser beams. "The study began in earnest when the Star Wars effort was winding down and some in the industry realized these big, high-powered military lasers could provide sufficient power to blast through rock," said Claude B. Reed, with the Argonne National Laboratory. "So GRI, along with the Colorado School of Mines, got access to two military lasers and ran some initial tests."

A revolutionary method for using laser beams to drill oil and gas wells moved a step closer to reality in the laboratories of the Colorado School of Mines. 

The university announced it has acquired six laser technology patents from Boeing in a major step forward in the transfer of military laser uses to civilian applications. If the adaptation of technology borrowed from Reagan-era "Star Wars" military programs is successful, it will mark the first fundamental change to rotary drilling techniques since the concept was invented in Britain in 1845. Laser s can slice through rock like a hot knife through butter, Graves said ( a professor of petroleum engineering at Mines) they would be much cheaper, much faster and much more environmentally benign than conventional drilling rigs.

Graves said, Laser drilling would have several advantages over conventional drilling :

-- Costs could be at least 10 times lower and up to several hundred times less than wells drilled with rotary rigs. For example, a typical, 10,000-foot gas well in Wyoming's Wind River Basin costs about $ 350,000 to drill. Laser drilling would drop that cost to $ 35,000 or lower. 

-- A laser drill's "footprint" -- the amount of surface space it occupies -- could be as little as 100 square feet, or even less with some models. 

-- The laser rigs could be transported to drilling sites in one semi-trailer load. Conventional rigs take up several thousand square feet of space and require numerous truck trips to haul equipment. 
-- Laser s could drill a typical natural- gas well in about 10 days, compared with 100 days for some conventional wells. 

"You're looking at three months of disruption versus a week or so of disruption with a laser drill. 
-- Laser s could be programmed for precise well diameters and depths. In addition, they could alternately drill coarsely to deliver mineral samples, finely to vaporize rock and leave no waste materials, or with intense heat to melt the walls of well bores, thus eliminating the need to place steel casing in wells.

GTI's initial study showed clearly that current laser technology is more than sufficient to break, melt or vaporize any lithology that may be encountered in the subsurface, and that the amount of energy required for spalling, melting or vaporizing rock was significantly overestimated by previous industry sources. For the most powerful laser experiments, as much as 6 pounds of rock were removed in about 4 seconds. In addition, it was found that the energy required to remove and alter the rock varies as much within lithologies as between them. Quantitative results as to minimum power required to remove rock or of factors that control power requirements were not determined. Other observations from these experiments related to cutting ease and speed, as well as altering rock properties. It was observed that calculated penetration rates for all the rock samples except salt were faster than rates observed by most conventional rock-removing mechanisms. Although not performed under in-situ conditions, it was clear that the cutting of hard rocks with close grain-to-grain contact was accomplished more easily than more porous rocks.

In addition, the thermal energy from the laser beam introduced some fundamental changes in rock properties. For example, the porosity and permeability of the rock surrounding the lased hole in a Berea sandstone sample actually increased.

Also, the experiments indicated that at such high powers, there were harmful secondary effects that increased as hole depth increased. These effects included the melting and remelting of broken material, exsolving gas in the lased hole, and induced fractures, all of which reduced the energy's efficiency in rock removal and therefore the rate of mass removal.

Current perforation techniques have remained the industry's primary method of wellbore perforation. An explosive force of shaped charges, originally designed for anti-tank weapons in World War II, focuses a penetrating, small-diameter jet through casing and cement into the reservoir rock. Although an instantaneous process, significant damage usually occurs to the formation. High power lasers could provide an alternative perforation method to reduce or eliminate formation damage, resulting in a significant boost in production rates, cumulative production and overall economic returns. GTI has repeatedly demonstrated through the application of high-power lasers to rock samples that damage to permeability and porosity of the adjacent zones can even be enhanced rather than damaged. By applying this technique down-hole, perforations and other directionally controlled completion and stimulation methods could be employed without damaging the reservoir.

A laser drilling system may provide some unique benefits:-

Ø Higher penetration rates and the ability to drill nonstop surface to total depth will likely reduce the total actual drilling time.

Ø The ability to create a tough, ceramic sheath in the borehole while drilling may reduce or eliminate the time required for setting steel casing in the well.

Ø Since the system has a permanent, hard-wired connection from the surface to the bottom-hole assembly, additional wires and/or optical fibers can be added to the bundle. This will allow the addition of many formation sensors, including televiewers and other imaging capabilities, delivering information to the surface in real-time and at incredibly high data transmission rates.

Ø The combination of the casing and sensing capabilities will eliminate the time required to run tools in and out of the hole, and will significantly reduce the time required for other activities.

Hence, it was found that high temperatures induced by lasers on rock samples could enhance porosity and permeability. High temperatures have been shown to evaporate or otherwise alter cementation minerals creating additional, connected pore space within the affected region. This result in improved conditions for the fluid to flow from the formation into the wellbore, as compared to the damage created to the rock through conventional applications of rotary drilling and explosive perforations.

Questions:-Answer all questions.

1. Discuss some unique benefits a "Laser Drilling System" will provide as compared to the conventional Rotary Drilling.(8 Marks)

2 "It was found that high temperatures, induced by Lasers on rock samples could enhance porosity and Permeability"; Do you agree with the statement? Justify your answer. (8 Marks)

3. When you are using the Laser technology in drilling a Gas well, what control do you have in the event of a Blow out? How do you mitigate it? (9 Marks)

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