Gas field development strategies and operational processes

Engineering

Gas Field Development

In gas field development, it is vital to clearly discover the structure and properties of the underground gas buildup and house them in surface facilities. The gas reservoir field data is the foundation for development of exploration and production planning. This includes the economic efficiency and lifecycle cost of the development of the field. After getting hold of the mining concession rights and confirming the existence of the gas, a development plan is put together. Based on the assessment of gas reservoir analysis results, the development planning of the gas field is started in order to optimize gas production. This includes gas processing facilities planning on the ground. During this planning, the gas recovery is optimized by looking at the gas production profile along with the gas properties and composition change over the lifetime of gas making. The determination of the Plateau Rate, along with the quantity of recovered gas and associated condensate, has a major force on a feasibility of the project including the initial investment cost effectiveness. Particularly, because the break-even point for the gas field development is generally low. So development plans need to be established taking long-term stable recovery into consideration (Gas Field Development, 2009).

There has been quite a bit of advances in drilling technology that have enabled the industry to find and develop oil and gas in the arctic and in the deep waters of the Gulf of Mexico. There were also dramatic changes occurring in recovery methods, as the industry learned to extract more oil and gas from fields. Many of these technological advances were forced on to the industry by the fact that most of the larger onshore fields had already been discovered (Boyce and Nostbakken, 2007).

Primary methods of recovery use the natural hydraulic pressure in a field to bring oil or gas to the surface. Secondary methods create a vacuum by pumping the oil or gas to the surface. Tertiary methods use water, natural gas, steam, thermal, or chemical injections into the fields to bring a larger portion of reserves to the surface. The secondary enhanced recovery methods were available from the early 1900s on, and tertiary methods have been in use in much of the second half of the twentieth century. Together, these methods have increased recovery from around 20% of in situ reserves with primary methods to over 60% for tertiary methods (Boyce and Nostbakken, 2007).

Since the gas reservoir pressure is higher than that of oil fields, greater attention in needed in regards to the type, number, location of the development wells along with the location of the gas processing facilities, and gas processing methods. Thought is also required in regards to toxic gases contained as impurities. The corrosion by gases and clogging that is caused by hydrates also need to be looked at. Currently development methods for reducing the environmental impact of gas development are being studied. Methods for diffusing not only of toxic gases but also of carbon dioxide that aggravates the greenhouse effect are being looked at (Gas Field Development, 2009).

Energy is vital to world quality of life and to global economics and security. The U.S. Bureau of Land Management (BLM) is responsible for managing 261 million acres of public land and another 700 million acres of subsurface minerals. The BLM maintains to improve the way it manages oil and gas development on the public lands. BLM put out a Best Management Practice (BMP) policy in June of 2004. The policy instructs field offices to incorporate appropriate BMPs into Applications for Permit to Drill and associated on- and off-lease rights-of-way approvals. By reducing the area of disturbance, adjusting the location of facilities, and using numerous other techniques to minimize environmental effects, BLM is significantly reducing impacts associated with new energy development to wildlife habitat, scenic quality, water quality, recreation opportunities, and other resources (What are Best Management Practices (BMP's), 2010).

Numerous oil and gas operatives have developed and used BMPs. BMPs are not one size fits all, what works for some does not work for others. The concrete practices and mitigation measures best for a particular site are evaluated through the National Environmental Policy Act process and vary to accommodate exclusive, site-specific conditions and local resource circumstances. Oil and natural gas making is a long-term, but not a permanent, use of public land. BMPs symbolize a commitment to the idea that smart planning and responsible follow-through decrease impacts to assets, both now and in the future. BMPs are a significant tool in the BLM's pursuit of enhancing quality of life for all citizens through balanced stewardship of America's public lands and resources (What are Best Management Practices (BMP's), 2010).

Best management practices (BMPs) are state-of-the-art mitigation actions applied to oil and natural gas drilling and production in order to help ensure that energy development is conducted in an environmentally responsible way. BMPs look after wildlife, air quality, and landscapes as people work to develop vitally needed domestic energy sources. Some BMPs are as simple as choosing a paint color that helps oil and gas equipment blend in with the natural surroundings, while others involve cutting-edge monitoring and production technologies. All are based on the thought that the footprint of energy growth should be as small and as light as possible (What are Best Management Practices (BMP's), 2010).

Utilization of oil and gas fields is becoming gradually more and more difficult and expensive. Many open fields start to decline and better recovery techniques are required to improve production and ultimate recovery and decrease impact on the environment. New fields frequently are in remote and environmentally unfriendly places, the reservoir rock is geologically complex and the hydrocarbon fluids are difficult, for example, oil is ultra heavy, gas is sour or otherwise polluted. In order to reduce the risk of developing such hydrocarbon reservoirs, large scale computer simulations are very useful. Current simulation methods, which were principally developed for the more straightforward reservoirs of the past, have to be extended and enhanced. Much bigger models, with much more geological detail, have to be replicated. Fluid chemistry and thermodynamics must be captured in more detail and indecision ranges in the simulated results have to be estimated dependably (Vink, n.d.).

Easily producible oil and gas is on the decline and residual hydrocarbon reserves require gradually more and more complex creation methods. In order to get the most out of the efficiency of these production methods, new techniques must be developed along with a better understanding of the subsurface oil and gas dynamics is necessary. Reservoir flow replication is an important tool for understanding the subsurface better, to examine novel production schemes and technique and to optimize the oil and gas field development strategies (Vink, n.d.).

Oil and gas are hydrocarbon fluid buildups in subsurface rock. They are the remnants of organic material that was deposited millions of years ago in swamps, river deltas, and sea lagoons and consequently covered by sediments. Over the course of time, the organic material changed into oil and gas and became the basis material for our present oil and gas fields. Because oil and gas is lighter than water, these fluids have an inclination to seep up through the rock towards the surface. This movement process is possible because rock is actually porous to fluid flow as it consists of solid grains with space between them. This space, called rock porosity, in some cases can be as large as 20-30% of the mass rock volume (Vink, n.d.).

Oil and gas can surge through this connected network of inter-grain pores in the rock. The process is sluggish, because most rock is not very permeable, since the pore space is small or the pores are poorly connected. Even with a very slow migration upward, there would be no hydrocarbons in our present time, if there would not be traps for the upward moving fluids. Such traps normally consist of layers of resistant dense and compact rock. The first is an anticline, a dome-shaped sealing layer with permeable rock underneath. The second trap is slightly more complex, and requires a fault, where the rock layers are broken and shifted (Vink, n.d.).

The first task for any triumphant oil company is to find reservoirs of trapped oil and gas. To some degree this relies on a mixture of clever guessing, delicate probing techniques and trial and error. The probing that is done into the subsurface is fairly incomplete. It should be quick, reasonably cheap and pierce very deeply. Using acoustic waves, seismic data acquisition, is currently the most widespread method. Here one launches sound blasts into the rock and records the echoes in arrays of responsive microphones. These seismic reflections contain information about the layering of rock porosity, density, and elasticity in the subsurface, but it is a formidable task to process the recorded acoustic data into meaningful information that could be used to decide if a certain location could contain trapped hydrocarbon accumulations. For the non-specialist such pictures at best give a hint of layering and fault structures, but specialists have learned to interpret these data and are able to identify possible or likely hydrocarbon reservoirs (Vink, n.d.).

Following this period of exploration one must tackle the seismic interpreters with their predictions and drill exploration wells. If these wells are on-shore, then the cost can be modest, but if the prospected reservoir is off-shore in ultra deep water, drilling a well is very expensive and it becomes an interesting strategy game to balance the risk of drilling a dry well against the risk of missing a big cat. Seismic data gives the wide contours of the reservoir but with low data motion. Near the exploration wells one can remove a very detailed picture of the reservoir rock and fluids, using down-hole logging tools that use quite advanced methods like gamma-rays, NMR and electrical resistivity, in order to map-out the reservoir properties very close to the well. Obviously there remains a lot of uncertainty in the reservoir properties even after combining seismic data, well-log data and educated guesses from experienced geophysicists and geologists (Vink, n.d.).

Reservoir engineers become involved when a reservoir has been found and its location has been roughly mapped out using the seismic data and data from the exploration wells. The duty of reservoir engineers is to use this information to make a field development plan, which explains in suitable detail where future production wells must be drilled and what type of production strategy will be employed. In the beginning of oil and gas recovery, reservoir engineering was simple. The process was to simply drill a hole and at some point there would be oil gushing out. If that did not happen, one would try again a bit farther out. These wells characteristically were in easily reachable locations and drilling depths were very reserved so the cost of drilling these wells was small. Currently a lot of the oil is offshore and drilling depths can broaden to extreme depths, the current depth record is close to 8 kilometers. It is more and more a condition to produce as much as technically possible from the subsurface oil and gas. With the simple strategy of primary depletion, it is only the intrinsic reservoir pressure that presses the oil to the surface, but this pressure declines rapidly and only a small fraction, 15-20%, of the oil can be recovered. In order to reach a higher ultimate recovery (UR), one must re-pressurize the reservoir, for example by injecting water or gas (Vink, n.d.).

Water and gas injection to re-pressurize the reservoir and push the oil towards producing wells are examples of secondary recovery. With secondary recuperation the UR can be significantly higher at almost 30-60%. However, the ambition nowadays is to reach ultimate recoveries of 70-80% and this requires even more enhanced oil recovery (EOR) techniques. Chemicals can be inserted that dissolve oil and wash-out the rock much more successfully than plain sea water does. Or chemicals can be used that make the oil less viscous so that it flows more easily to the producing wells. This viscosity decline is mandatory when attempting to recover very heavy oil or bitumen. This kind of hydrocarbon looks more like the material that is used to make a hockey puck as it essentially is a solid unless it is heated up significantly. Yet an additional quite advanced recovery technique uses air insertion. The oxygen that is in the air act in response with the heavy oil, and this burning manufactures heat and gases that helps to push the oil forward. At the same time, the burning change heavy hydrocarbons into lighter ones and a small percentage of coal-type remains. If such a process can be controlled at the field scale, the UR could be as high as 80-90% (Vink, n.d.).

With the need for these more advanced field development concepts, the role of the reservoir engineer has become more important and also the need grows for tools to help developing such plans, preferable finding the options with the largest chance of a high ultimate recovery on an economically attractive time scale and with the least environmental impact. Reservoir flow reproduction is the main quantitative tool that allows exploring option development concepts and can give forecasts with uncertainty ranges for the various options. Also the distinctiveness of new or complex EOR methods can be investigated, for example the result of injecting steam, or polymers that can dissolve oil, or other chemicals or even bacteria. By uniting lab scale experiments with field-scale reservoir simulations, the margins of doubt around applying such novel and usually expensive improved recovery methods can be reduced (Vink, n.d.).

Natural gas processing is a procedure that starts at the wellhead. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. The natural gas produced from oil wells is generally classified as associated-dissolved, which means that the natural gas is associated with or dissolved in crude oil. Natural gas production absent any association with crude oil is classified as non-associated. In 2004, 75% of U.S. wellhead production of natural gas was non-associated. Most natural gas production contains, to varying degrees, small hydrocarbon molecules in addition to methane. Although they exist in a gaseous state at underground pressures, these molecules will become liquid at normal atmospheric pressure. Collectively, they are called condensates (Cohen, 2006).

An ideal field would be one with a very high porosity and permeability reservoir with great continuity, like a pay zone in a well on one side of the field looks like a pay zone in a well on the other side of the field, and there is one continuous, high porosity and high permeability reservoir. Our ideal field could be developed with a minimum number of wellbores, with low decline rates per well. A less than ideal field would be a series of discrete reservoirs, with little or no continuity between the discrete reservoirs. To fully develop our less than ideal field would require far more wells than the ideal field. Also, given the limited volume in each reservoir, the decline rate per well would be fairly high (Cohen, 2006).

Petroleum, commonly referred to as oil, is a natural fuel formed from the decay of plants and animals buried beneath the ground, under tremendous heat and pressure, for millions of years. Formed by a similar process, natural gas often is found in separate deposits and is sometimes mixed with oil. Because oil and gas are difficult to locate, exploration and drilling are key activities in the oil and gas extraction industry. Oil and natural gas furnish about three-fifths of our energy needs, fueling our homes, workplaces, factories, and transportation systems. In addition, they constitute the raw materials for plastics, chemicals, medicines, fertilizers, and synthetic fibers (Oil and Gas Extraction, n.d.).

Using a variety of methods, on land and at sea, small crews of specialized workers search for geologic formations that are likely to contain oil and gas. Sophisticated equipment and advances in computer technology have increased the productivity of exploration. Maps of potential deposits now are made using remote sensing satellites. Seismic prospecting, a technique based on measuring the time it takes sound waves to travel through underground formations and return to the surface has revolutionized oil and gas exploration. Computers and advanced software analyze seismic data to provide three-dimensional models of subsurface rock formations. This technique lowers the risk involved in exploring by allowing scientists to locate and identify structural oil and gas reservoirs and the best locations to drill. Four-D, or "time-lapsed," seismic technology tracks the movement of fluids over time and enhances production performance even further. Another method of searching for oil and gas is based on collecting and analyzing core samples of rock, clay, and sand in the earth's layers (Oil and Gas Extraction, n.d.).

After scientific studies indicate the possible presence of oil, an oil company selects a well site and installs a derrick or tower like steel structure in order to support the drilling equipment. A hole is drilled deep in the earth until oil or gas is found, or the company abandons the effort. Similar techniques are employed in offshore drilling, except that the drilling equipment is part of a steel platform that either sits on the ocean floor, or floats on the surface and is anchored to the ocean floor. Although some large oil companies do their own drilling, most land and offshore drilling is done by contractors (Oil and Gas Extraction, n.d.).

In rotary drilling, a rotating bit attached to a length of hollow drill pipe bores a hole in the ground by chipping and cutting rock. As the bit cuts deeper, more pipe is added. A stream of drilling mud which is a mixture of clay, chemicals, and water, is continuously pumped through the drill pipe and through holes in the drill bit. Its purpose is to cool the drill bit, plaster the walls of the hole to prevent cave-ins, carry crushed rock to the surface, and prevent blowouts by equalizing pressure inside the hole. When a drill bit wears out, all drill pipes must be removed from the hole a section at a time, the bit replaced, and the pipe returned to the hole. New materials and better designs have advanced drill bit technology, permitting faster, more cost-effective drilling for longer periods (Oil and Gas Extraction, n.d.).

Advancements in directional or horizontal drilling techniques, which allow increased access to potential reserves, have had a significant impact on drilling capabilities. Drilling begins vertically, but the drill bit can be turned so that drilling can continue at an angle of up to 90 degrees. This technique extends the drill's reach, enabling it to reach separate pockets of oil or gas. Because constructing new platforms is costly, this technique commonly is employed by offshore drilling operations. When oil or gas is found, the drill pipe and bit are pulled from the well, and metal pipe is lowered into the hole and cemented in place. The casing's upper end is fastened to a system of pipes and valves called a wellhead, through which natural pressure forces the oil or gas into separation and storage tanks. If natural pressure is not great enough to force the oil to the surface, pumps may be used. In some cases, water, steam, or gas may be injected into the oil-producing formation to improve recovery (Oil and Gas Extraction, n.d.).

Crude oil is transported to refineries by pipeline, ship, barge, truck, or railroad. Natural gas usually is transported to processing plants by pipeline. While oil refineries may be many thousands of miles away from the producing fields, gas processing plants usually are near the fields, so that impurities like water, sulfur, and natural gas liquids can be removed before the gas is piped to customers. The oil refining industry is considered a separate industry, and its activities are not covered here, even though many oil companies both extract and refine oil.

The oil and gas extraction industry has experienced both booms and busts over the years, illustrating the cyclical relationship between the price of oil and employment. Generally, the reaction of the labor market lags slightly behind the price fluctuations because oil companies must adjust their production levels accordingly. During the 1970s and early 1980s, the price of crude oil rose sharply, stimulating domestic exploration and production. Between 1978 and 1982, the year in which industry employment peaked, this industry grew 65%, creating 279,000 jobs, while employment in the economy as a whole remained flat during this period. Employment rose one-and-a-half times as fast in the oil and gas field services segment as in the crude petroleum, natural gas, and natural gas liquids segment, reflecting the fact that most exploration and drilling is done on a contract basis. Starting in 1982, oil-producing countries around the world began yielding much larger volumes of crude oil, driving prices down; this culminated in the collapse of oil prices in the mid-1980s. During this time, the industry experienced a sharp decline in domestic exploration and production and an extended period of downsizing and restructuring, losing more than 415,000 jobs from 1982 to 1999. As was the case during the boom period, employment in oil and gas field services changed more than did employment in crude petroleum and natural gas production (Oil and Gas Extraction, n.d.).

Currently, simulation tools like Dynamo/MoReS or commercial simulators like Eclipse, are well suited for field development planning of easy to medium difficult reservoirs. However, as mentioned in the introduction, the easily accessible oil and gas is dwindling and there is a growing need for clever development options applicable to very difficult cases. There is still a huge hydrocarbon reserve in Canada; however this is in the form of very heavy oils and bitumen that cannot be recovered using conventional reservoir engineering methods. Also the simulation tools must be extended to make them usable for these and other EOR cases. In the industry one can recognize a number of directions along which simulation tools are being developed or extended.

Integration. This involves connecting data and functionality along the full modeling workflow. The (static) reservoir properties are addressed with seismic tools and geo-statistical packages; reservoir dynamics is modeled in fluid flow, well and facility simulators; the results are processed in economical and risk assessment packages. It is a formidable task to connect all data and tools in a smoothly integrated workflow.

Ease-of-use. Reservoir simulation involves a lot of input data and produces large amounts of output. This data must be checked and validated and the reservoir engineer must keep a good overview of what the simulator is actually computing. This requires an extensive, intuitive graphical user interface.

Optimization under uncertainty. In essence the aim of reservoir simulation is to find an optimal field development plan. However, much of the input data is only roughly known and there is hopefully quantifiable uncertainty in the model. Hence the task of a simulation tool suite is to help the reservoir engineer in optimizing models in the presence of uncertainty.

Speed and efficiency. Improving the model quality by increasing grid resolution increases CPU times and memory requirements. Also the need to capture model uncertainty be simulating a large number of equally probable model realizations increases the computational burden. Hence, there is an urgent drive to find faster numerical methods, to apply more efficient parallelization methods.

Advanced physics and processes. Many of the EOR techniques require a much more detailed understanding of the processes that take place in the reservoir. Such processes involve more than fluid displacement and thermodynamics: exothermal chemical reactions, diffusion and adsorption processes, rock geo-mechanics etc. (Vink, n.d.).

Following success in the exploration phase with the delineation of coal seam gas reserves, the next phase is the development of the gas field. The main stages of the development process are: Stage 1: Gas field planning; Stage 2: Landholder and government consultation; Stage 3: Ground-truthing, soil tests and survey works; Stage 4: Construction of gas field infrastructure to include, well site and pipeline setup, service corridor construction, drilling operations, workover operations, surface equipment connection, gas compression plants and coal seam gas water storage; Stage 5: Commissioning plant; Stage 6: Production and gas field operation; Stage 7: Workover and gas field maintenance, and Stage 8: Rehabilitation and decommissioning (Coal seam gas project development guidelines, n.d.).

The Development Plan (DP) at this stage is conceptual to the extent that final engineering design and on-site ground testing required for fixed facilities has not yet been done and only preliminary discussions with landholders held. A full development plan of the intended gas field is created over a series of months. Wherever possible, gas field infrastructure is located in areas of low intensity land use. The planning guidelines consider the following planning constraints:

where practical access tracks are located along existing boundary tracks or along fence lines and road reserves well sites are located where possible on the fringes of intensive land use, in corners of paddocks, or areas of land unsuitable for farming and on or near access tracks, right of ways, easements and road reserves compressor plants constructed on land owned by Arrow or on land in agreement with the landowner pipelines on road reserves where possible drainage lines will be maintained and erosion control devices put in place (Coal seam gas project development guidelines, n.d.).

The actual spacing between wells is based on work completed during the exploration phase and the predicted gas field pressure and expected gas flows. Currently the spacing is about 900m between wells. In general, the well site footprint will be 40m by 60m. As we move away from creating drilling pits in areas of intense land use, the impact on the land will be minimized and the rehabilitation cycle reduced. All compacted areas will be ripped and surface erosion controls put in place as required. All wheel ruts and waste will be removed with drainage lines replaced (Coal seam gas project development guidelines, n.d.).

The wells are usually connected by service corridors. These corridors contain gathering lines consisting of inert water and gas pipelines. The placement of infrastructure such as well sites, access tracks, gas water and electricity service pipelines and cables are based on a minimal local disturbance design location of surface corridors is given to existing roadways and reserves, and as much as possible along existing fence lines. Yet, there are occasions where other locations need to step out into farming lands (Coal seam gas project development guidelines, n.d.).

An assessment of potential noise levels from different machines is available from the manufacturer. The distance to noise sensitive areas is used to calculate the best noise emission controls when placing machinery in the field. Opportunities to reduce noise such as ordering specific grade noise mufflers, changing from reciprocating engine powered pumps to electrical powered pumps are investigated. Initial draft services corridors and well sites are selected - power, gas, water pipelines and access track details are normally in the one service corridor. This information is usually included on a map for discussion with the landholder and government licensing bodies as required (Coal seam gas project development guidelines, n.d.).

Much of the investigation sequence is done before the wells are even drilled. Once a company obtains the mineral rights to the land it wishes to drill, three-dimensional (3-D) seismography, aboveground sonic sampling, and other methodologies are utilized to determine where oil is most likely to be found. After seismographic data about either underground or sea floor rock is gathered, it is looked at for signs of oil or gas deposits. This process can take quite a few months to complete. A probable area is then selected, and exploratory or wildcat wells are drilled in order to corroborate the suspicions. If the area is identified as having oil, then development wells are drilled. There are legal policies that set the number of wells that can be drilled in an area using infill drilling. Drilling to check for the potential of expanding an oil field is done with stepout wells. Wells that offer up no product, or too little to make sustained drilling feasible, are called dry holes. While drilling, a rig containing a derrick and surface equipment is set up over the target area, and a bit that is attached to a drill stem is lowered into the earth. In the most ordinary setup of rotary drilling, a rotating bit that is connected to a hollow pipe ruptures up the earth. Substances made up of clay, water, and other ingredients are inserted through the pipe to chill the rotating bit and carry busted rock back to the surface. Frequently a hollow covering is placed in the well to keep the walls from giving in and to guard the contents of the well from outside things like water or gas. Both oil and gas are removed through a narrow tubing apparatus that brings the material to the surface (Oil and gas field exploration services (SIC 1382), 2010).

The crude oil that builds up without pumping has to be collected by using primary recovery methods. During secondary recovery, additional effort must be spent to remove the oil. Most often, the well is inundated with water in order to flush out the oil. In some wells, tertiary recovery methods, such as injecting steam or gases into the well, help wash out the heaviest, most sticky oil. Wells may be shut in, meaning their valves are closed. This is often done during the wait for a pipeline link or when the oil and gas market is down and further drilling becomes unnecessary. Once a well is dry, it is plugged or filled with cement and deserted (Oil and gas field exploration services (SIC 1382), 2010).

Drilling for natural gas is a lot like drilling for oil, but gas must be liquefied before it can be shipped. Apart from the natural gas liquids (NGL) that occur naturally at a well, all gas obtained must be cooled and pressurized into liquid natural gas (LNG) for transportation. NGL is mainly ethane, propane, butane, and natural gasoline; the gas from LNG is mainly composed of propane, propylene, butanes, and butylenes. The amount of oil obtained is measured in barrels (bbls.), one of which is equal to 42 U.S. gallons. Natural gas is measured in thousand cubic feet (mcf), one of which equals 1 million BTUs (British thermal unit) of energy at one atmosphere of pressure. One barrel of oil is equal to six mcf (Oil and gas field exploration services (SIC 1382), 2010).

Fortune magazine has reported that there have been dramatic strides in oil exploration technology of late. In 1965 drillers could only operate in water up to 300 feet deep. By the late 1990s, Chevron was leasing blocks of land in the Gulf of Mexico 9,000 feet underwater. Some experts said that drilling in 10,000 feet was imminent. Chevron and other companies were developing a technique called subsea mud-lift drilling, which enabled drillers to leave residue on the ocean floor instead of sucking it up through a pipe. This method could save drillers $5 million to $10 million per well (SIC 1382), 2010).

New tools like three-dimensional seismic analysis allow oil companies to bounce sound waves off oil-bearing deposits and translate the patterns into 3-D models. Drilling rigs using the technique find productive wells more than 70% of the time, compared to a 40% success rate with conventional seismic analysis. In addition, producers could extract more oil from existing wells. Oil & Gas Journal has reported on a new fracturing technique that allowed gas drillers to stimulate existing wells rather than drilling new wells. Major U.S. producers could pump as much as 50% of the oil from a given pool, compared to a worldwide average of less than 35% (Oil and gas field exploration services (SIC 1382), 2010).

As the large oil companies cut back on domestic exploration through the 1990s, it became even more important to make as certain as possible the profitability of those explorations that were undertaken. Technology for assessing the shape of underground earth formations, and oil and gas deposits was introduced as early as 1927 by Schlumberger Ltd., which maintained a hold on the industry through 1996, with nearly $9 billion in annual revenues. Schlumberger's Maxis service, which assesses the characteristics of earth around a well, was introduced in the early 1990s. At a time when profits were flat and downsizing common, Schlumberger doubled its jobs in 1992, testament to the industry's ever-increasing reliance on high technology (Oil and gas field exploration services (SIC 1382), 2010).

But Maxis was only one of many high-technology innovations that reduced oil exploration costs and more than halved finding costs for natural gas in the late 1980s and early 1990s. Other innovations included horizontal drilling, three-dimensional (3-D) seismography, and improvements in drilling in light sands. The majority of innovation was in offshore drilling, which required much technological innovation in both the exploration and drilling stages. The Machar project in the North Sea used both advanced technology and an innovative system to tap a difficult oil well. Discovered in 1972 and estimated to hold 55 million barrels of recoverable oil, the reservoir was too complex to confidently evaluate with the technology of the day and considered too marginal economically. In 1994 British Petroleum enlisted what became the Turnkey Additional Production (TAP) alliance, which drew together contractors to supply the best possible solutions, one of them being Schlumberger Integrated Project Management (IPM), managing well engineering and well construction. All parties participated in risk and reward, so all focused on reducing risk, maximizing efficiency, and maximizing return. Decisions were made rapidly by those nearest the action, instead of relying on a chain of management. The results were quick and impressive; instead of the usual one to two years typical when using the conventional approach, appraisal oil flowed in just 19 weeks. At the end of the 25-month project, there had been no work loss due to accidents, no leaks or spills, and an overall efficiency 7% above plan (Oil and gas field exploration services (SIC 1382), 2010).

Although invented in the 1960s, three-dimensional (3-D) seismography only became viable in the 1980s with advances in the computer and acoustical industries. Ships equipped with two cables each carrying two source arrays or seismic streamers cruise areas of suspected undersea oil and gas deposits. The streamers give off electric or air detonations, whose waves are reflected off underwater rock formations below the level of the sea floor. Data is then processed onshore and the undersea floor mapped. Although ships covered much terrain, it could take as much as a year and a half to interpret the data gained from 100 square miles. Because of the presence of aboveground structures, 3-D seismography was impractical on land. Instead, trucks called thumpers sent sonic waves through the ground by hammering the earth at specific sites; the wave data was then collected and interpreted (Oil and gas field exploration services (SIC 1382), 2010).

An example of a gas field that is under development is that of the South Pars / North Dome field which is a gas condensate field located in the Persian Gulf. It is the world's largest gas field, shared between Iran and Qatar. This gas field covers an area of 9700 square kilometers, of which 3700 square kilometers (South Pars) is in Iranian territorial waters and 6000 square kilometers (North Dome) is in Qatari territorial waters. The field consists of two independent gas-bearing formations, Kangan (Triassic) and Upper Dalan (Permian). Each formation is divided into two different reservoir layers, separated by impermeable barriers. The field consists of four independent reservoir layers K1, K2, K3, and K4. The field is a part of the N-trending Qatar Arch structural feature that is bounded by Zagros fold belt to the north and northeast. In the field, gas accumulation is mostly limited to the Permian -- Triassic stratigraphic units. These units known as the "Kangan -- Dalan Formations" constitute very extensive natural gas reservoirs in the field and Persian Gulf area, which composed of carbonate -- evaporite series also known as the Khuff Formation (South Pars / North Dome Gas-Condensate field, 2010).

The South Pars Field was discovered in 1990 by NIOC National Iranian Oil Company. Field development has been delayed by various technical problems like high levels of mercaptans and foul-smelling sulfur compounds, contractual issues and politics. Gas production started from the field by commissioning phase 2 in December 2002 to produce 1 bscf/d of wet gas. Gas is sent to shore via pipeline, and processed at Assaluyeh. NIOC is planning to develop the field in 24 to 30 phases, capable of producing about 25 to 30 bcf of gas per day (South Pars / North Dome Gas-Condensate field, 2010).

Each standard phase is defined for daily production of 1 bcf of gas, 40,000 bbl of condensate, 1500 tonnes of LPG and 200 tonnes of Sulfur; however some phases have some different production plans. Each of the phases is estimated to have an average capital spend of around U.S.$1.5bn, and most will be led by foreign oil firms working in partnership with local companies. The government which came into power in 2005 has favored local firms over foreign companies in the energy and other sectors. By the beginning of 2008 phases 1,2,3,4 and 5 has been brought to production and by the end of 2008 phases 6,7,8,9 and 10 will be on stream. Phases 12,15,16,17,18,19,27 and 28 are under different development stages (South Pars / North Dome Gas-Condensate field, 2010).

The Iranian constitution prohibits the granting of petroleum rights on a concessionary basis or direct equity stake. However, the 1987 Petroleum Law permits the establishment of contracts between the Ministry of Petroleum, state companies and "local and foreign national persons and legal entities. The Oil Ministry has called for the issue of more than $12 billion worth of bonds for a period of three years. While several phases of South Pars gas field are still waiting for development and the ongoing development phases are facing delays, NIOC authorities are conducting negotiations for development of other Iranian offshore gas fields. Many Iranian energy analysts believe that NICO authorities should focus on full development of South Pars field prior to conduction of any new project for development of other undeveloped Iranian offshore gas fields. The priority of South Pars full development is not only due to its shared nature with Qatar, but also with huge capability of the field to add significant liquid production to Iranian liquid export capacity (South Pars / North Dome Gas-Condensate field, 2010).