Prudhoe Oil Field Development Plan
Prudhoe Bay lies in the Northern limits of Alaska in the area of 40 by 15 miles (Dolewsk n.d). Bordering on the Arctic Ocean, this bay is considered as the largest crude oil reserve field in North America with its capacity that may be estimated for 25 billion barrels of crude oil, and with 13 billion barrels recoverable. The bulk of this region is snow covered; the oil and gas reservoir lies embedded in the porous rock below the surface, between 5000 and 20000 ft in varying areas. The majority of gas and oil may rise up to the surface due to its own pressure built in a geological pattern (Dolewsk n.d). The geology of Prudhoe is a complex combination of sandy deposits, silica cements and refined clays. The oil reservoir is a result of four geological formations in varying depths. The most potent oil reservoir is held in sandstone of the Sadlerochit type estimated to be at 9000 feet underground (Dolewsk n.d.).
Reservoir Type and Production Strategies
Broadly categorized, oil/gas reservoirs may be classified according to the product they bear; they can be gas reservoirs only, oil only reservoirs, or gas and oil reservoirs containing both products. Shallow wells usually bear gas or oil with very few producing both. This is because shallow wells often experience a gas leakage into the surface, which in itself can ease the exploration work (Texas State Historical Association n.d). In addition, deep wells will almost always bear a combination of oil and gas, mainly because gas is usually trapped within the oil bearing rock deposits or basins. The Prudhoe Bay is a combination reservoir having both gas and oil. The Prudhoe Bay is an onshore expanse, with surface deposits in the form of traps and underneath traps. The production of oil from the Prudhoe Bay will incorporate drilling multiple wells into the oil rich porous sandstone in order to verify the oil production potential of the basin (Trzupek 2002).
Production Processing Overview
The intended method of production is by drilling of wells to pass through the oil/gas rich strata at the depths ranging from 4000-9000 feet in the initial stage. The drilling process will involve setting up several 30 meter tall rig machines in various exploration sites, in which the preliminary tests indicate potentially high product profiles. These rig machines will sink drill rods (10 meters standard) into the crust which will use trepans attached to a deep end to crush rock fragments in the shaft. Drilling mud will be injected into the bore in order to prevent overheating of trepan, to set the proper wall hardness to prevent blow-outs, as well as to help obtaining the crust composition samples for an analysis (Dietzmann & Springer 1974).
Once the oil rich strata have been reached, small perforations will be drilled at the pipe sides to allow product seepage or collection into the drill pipes and subsequent collection at the surface. Initially, it is expected that the natural pressure of oil/gas mixture in the basin will be sufficient to drive it to the surface, but later methods such as surface pumps and down-hole pumps may be applied (“Texas State Historical Association” n.d). In the primary stages of the project, oil/gas mixtures will be collected on the surface of near surface shallow bores through a natural displacement due to relative densities of three products, as well as due to the geological pressure sustained by the trap column. This stage will expect to gain a recovery factor of 10-20% of the total potential yield.
The third phase, expected in 20-25 years, will involve some Thermally Enhanced Oil Recovery methods (TOER). This phase will target mainly the high density oil still trapped in lower segments of the oil column. In this stage, a high pressure steam will be blasted at the oil rich sandstone banks in the depths of 9000-15000 feet. Vertical and horizontal shafts will be used to reach the deposits. The steam will reduce the density of heavy oil, as well as improve its fluidity to enable the collection. This phase may aid in the retrieval of the further 5-15% of reserves in the bay. This step will be dependent on the operational profitability of the project. As the project enters its secondary stage, the product will be driven into collection bores through the injection pressure provided by the Water-Alternating-Gas (WAG) injectors. These injectors will be channeled into the porous column using the recycled natural gas and water obtained from the oil basin (Trzupek 2002). The recovery factor expected through the re-injection will be 30-40 % of total oil yield in the bay.
The collected product will be channeled to designate the separation and processing plants where various components will be isolated and purified. The Prudhoe basin is thought to contain oil and gas trapped with mixtures of sand and water. The detailed extraction and purification process will be handled in the next session.
Preliminary Data Collection
The viability of Prudhoe production will be ascertained through some conventional data collection methods used in the hydrocarbon exploration. Even though more modern methods have been developed and will be used in the Prudhoe area, the natural surface seepage, being the oldest exploration tool, has indicated the presence of varying intensities of hydrocarbons in the North Slope area. More than 30 small seepage areas have been identified in 600 square miles area. In addition, distributed areas of porous liquids with the low American Petroleum Institute’s (API) density have been observed in the shore-side regions of water-oil contact, suggesting the presence of high density crude oil of API values between 21 – 30 degrees. Magnetic methods initially conducted in the basin have indicated significant areas of low magnetic strength (both the surface balance and magnetometic values).
This, along with the presence of porous sandstone outcrops in the seaward side of the region suggests the presence of low-magnetic sedimentary rocks consistent with those found in hydrocarbon rich columns (Wilkirson et al. 1988). Seismic studies conducted in the region lead to the conclusions that salt domes, typical of oil basin strata, are found in some areas in the field. Stratigraphy studies have indicated the area to be bounded by complex geological timelines including sedimentary rock faults, impermeable shale slopping seaward meeting some porous sandstone in the depths from 600 -4000 feet, possibly trapping oil, gas and water in the ground. A large aquifer has also been associated with the area just underneath the surface, forming a viable pressure area that may aid in the natural flow of hydrocarbons during extraction.
The bulk of operations in the phase one will not require any stimulation as the overlying layers will be shallow. In addition, sufficient large volumes of oil/gas/water are expected to lie near the surface in such a manner as to prevent any pore blocking, pressure drop or suck-backs in the oil rock that would reduce yield. In the later phases, with well depths above 9000 feet, it is expected that the heavy oil seepage into the minute pores will be a slow process. Hydraulic fracturing at the depths above 5000 feet may be in order for rock pore widening as well as warming up oil to improve the mobility (British Petroleum 2006).
A reservoir simulation will aid in mapping the three dimensional geological areas as well as a geometrical composition of the entire area covered by the aquifer, as well as surrounding areas. This information will aid in designing some well stimulation techniques to give a maximum yield. The Finite Difference (FD) simulation will be used to study the region, with a specific interest in dynamics of fluid phase behavior, some total mass conservation techniques and porous media flow estimation against the temperature change algorithms (Peters et al. 2006). The preliminary simulation indicates an area of 15 miles by 40 miles and of varying depths, with the mean depth being 4000 feet. The parent rock is mainly sandstone of thickness 0-6 meters, with the porosity ranges of 17 – 22 % and permeability figures between 5-15 millidarcays. The API gravity of retrieved sediments show the mineral composition which gives yield estimates of 25 million barrels, with 13 billion barrels producible using conventional technologies. The structure of basin also indicates some areas of heavy oil presence, suggesting a need for the well stimulation techniques in a tertiary phase of production.
Estimation of Product Profiles from Prudhoe Bay
The bay has calculated a potential for the production of gas and oil of different densities as indicated in the strata graphic and remote sensing methods. In addition, the region has some huge underlying saline deposits with water aquifers and semi-formed organic sediments. The projected capacity of basin is 25,000,000,000 barrels of oil with the peak daily production of 1,000,000 barrels per day in the initial phase, dropping to half of the daily capacity in the secondary production stage (British Petroleum 2006). The tertiary stage may experience a decline to slightly less than 300,000 barrels per day. Half of the total potential yield of bay, nearly 13 billion barrels, can be recoverable in the economically viable range and using some conventional techniques. In addition, the greater North Slope field has a natural gas yield potential of 35 trillion cubic feet, with the expected daily gas yields upward of 8, 000,000,000 cubic feet of gas daily at the peak of production. The gas will be used for commercial purposes, as well as for the re-injection into drill bores for pressure maintenance and fracturing. A small percentage will be used for local energy needs (Peters et al. 2006).
This chapter describes the operational processes of producing the Prudhoe Bay.
Production, Processing and Transit Equipment
The Prudhoe Bay production, like any other oil field production, will incorporate three stages. The stage includes prospecting and drilling, production and refining, and the transit (transportation) stages.
Prospecting and Drilling Equipment
The exploration equipment such as magnetometers, surface balances, electric transducers and hydrometers among others. The rig machinery includes derricks, rods, and trepans, horse heads, walking beams, prime-movers, counter weights, Samson posts, stuffing boxes, pump jacks and bridles.
Production and Refinery Equipment
The recovery equipment comprises of pipes, valves, pumps and draw-works among others. The mud equipment includes pumps, rotors, and shale shakers, while the injection equipment includes chemicals, degassers, de-silters, hoses and pressure equipment. On the other hand, the refinery equipment includes fractionating columns, separators, piping, storage systems, heat systems, reaction systems.
Transportation (Transit) Equipment
The transit systems include pipelines, valves, master and line meters, reservoirs and depots and all the associated equipment. The major transport means to be used will be transnational pipelines, but the considerations will be in place to include up to four double-hulled ocean tankers as an alternative transportation equipment.
Processing (Surface and Refining)
The initial operation will include sinking 600 wells of natural flow, 400 wells of gas lift as well as 300 wells with injectors. The injected wells will use the Water Alternating Gas (WAG) type equipment, with both water and gas being recycled from the natural well products. The injection will be up to 200 MMCFD, with the expected pressure buildups up to 2000 psi. The natural flow wells will be maintained at 2400 psi, with corrosion resistance enhancements. The injection pipe tubing will have the diameters ranging from 3.5 to 7 inches to tolerate the high pressure amounts. The extended reach drilling (ERD) and Ultra Extended reach Drilling (UERD) will be used to sink wells as deep as 10000 feet and horizontal departures as much as 4000 feet from a main down-hole area.
The reservoir terrain may usually contain up to four materials: oil, gas, water and sand. The surface retrieved mixture must, therefore, be separated before the further processing. The water normally in oil basins is salinated and is usually 200-300 kg/ tone of production. In addition, dissolve minerals of 10 -15 kg per cubic meter may be present. In addition, natural gas present in the production is in the range of 50 -80 M3/tone. These materials negatively affect the production as well as the transportation of oil, thus, they must be separated from the mixture. Sand, present in a suspended form in the mixture, is also separated before the further processing (British Petroleum 2006).
Water is an expected byproduct in the Prudhoe Bay oil production. The estimated volumes per metric ton of raw produce is between 200-300 Kg/t. water will be separated from the mixture in the oil dehydration sump. To do this, heating will take place in the sump followed by pumping of mixture and mixing with the 30-60 grams of a demulsifying agent. This will happen at the modular manifold before the emulsion has been sent to the heat exchange. Due to the infrastructural orientation of the Prudhoe Oil facility, a demulsifier injection will take place 100 meters before the mixture reaches the separator, where its effect will ease the dumping of water and surfactant to leave the oil behind. The water-oil separation requires heat in order to aid in demulsification. The mixture is pre-heated to 60 -70 degrees centigrade before entering a separator. The separated water exiting the oil sump will be re-used for injection purposes (Abdel-Aal 2004)
Gas separation will take place in two stages. The first stage will involve a temporary separation for the purposes of a component volumetric analysis in the Gas Metering station (GMS) just after the produce extraction. The impure components will then be recombined and sent through the collector to the booster pumping station for the gas extraction. The remaining components will mainly be partly the degassed oil and saline water mixture. Final degassing will be done at the oil Treatment Facility (OTF) to obtain gas free oil. A modular manifold pressure will be sustained at between 1 – 1.5 Mega Pascal, high enough to allow gas to exit from the separator and flow to the Gas processing Plant (GPP). The separated gas will undergo dehydration through the exposure to aromatic hydrocarbons such as ethylene to absorb the water in commercial gas. In the later phases, commercial gas fractionation will be carried out to obtain different gas products (British Petroleum 2006).
From the separator, oil will be in the major part water free, but the complete dehydration will still be necessary. In addition, it is estimated that this oil will have 500-1000 mg/liter of salt, which needs to be extracted (Wilkirson et Al. 1988). Therefore, fresh water will be re-introduced in the oil/salt mixture to dissolve the mineral deposits in oil. This oil will then proceed to an electric dehydrator for a complete water removal. This final product will be ready for grading and packaging in the readiness for transit.
The Prudhoe Basin is based on sandstone as the oil rock. Sand will, therefore, be a component of produced mixture, mainly in minute fragments. Sand particles, being of the higher density and larger granular attributes than any other component, may be separated by a mass filtration and sedimentation on a small scale. The huge amount of filtrate obtainable per day in the production will require more modern and robust as well as faster means of separation. The proposed method is to run the oil in a stir loop and to add the Toluene and Imidazolium IL in order to form separation layers with sand and clay particles remaining at the bottom. The distillate will then be guided away under a gravitational free flow to leave the mineralized, but mainly sediment free oil ready for the electric de-mineralization and dehydration in the next stages.
The heat exchange is used to indirectly transfer heat from one oil column to another without any physical contact of the two media. In the oil refinery operation, oil is pre-heated in the heat exchanger area before being transported to the separator. This pre-heating helps in demulsification and prepares the oil/water/surfactant mixer for a next stage of separation. In the Prudhoe oil production, this installation will precede the separator and oil sump units and the pipeline joining the heat exchanger to the main separator will be about 100M long to allow the sufficient demulsification of extract components. To mitigate effects of fouling in the heat exchange, a regular chemical treatment of exchanger will be scheduled in order to eliminate or reduce the energy related losses associated with the product fouling in the exchanger (British Petroleum 2006).
The initial phases of the Prudhoe project may not involve commercial sales of gas. The factory installation will, however, be constructed to accommodate the fractional distillation of gas into various products of different octane rating, boiling points and densities. The heat exchange will be used to pre-heat the oil to temperatures in the range of 260-380 degrees in the preparation for channeling into the distillation column (Jones 1971). The intended distillation products will include heavy oil products such as lubricating oil, wax and asphalt (collected at the temperatures between 380-400 degrees), fuel oil (370 –320 degrees), diesel oils (less than 300 degrees), kerosene (collected at 200 degrees), gasoline (150 degrees) and lighter gases collected at less than 100 degrees.
The internal bore corrosion in the bay is expected to be from a carbon dioxide action. The conditions of high temperatures (about 200 degrees F) coupled with the relatively high CO2 presence in the reservoir gas of 12% may accelerate pipes corrosion. To mitigate this, chemical treatments will be added, including 13Cr tubing which has an excellent resistance (Jones 1971).
This chapter will highlight the expected logistical estimates for the Prudhoe Bay production. The estimates are made with the assumption of the project time of 25 years, based on the U.S dollar in the current exchange rates, without any adjustment for inflation. The figures may vary in the course of the project implementation based on some economic patterns, labor demands and emerging developments in the operational dynamics of project.
- The initial number of prospecting labor in persons is 1500 (with the total operational capacity of 1300 wells and daily throughput of 1 million barrels per day).
- The expected lifespan of natural flow production is 8-10 years, the injection production 10 years and gas lifting 7 years. Various phases may overlap.
- The project will be supported by three processing plants distributed radially within the production field and connected through a pipe network within the area. The output from each of wells will join the collection lines to the plants.
- The estimated cost in the U.S dollars for the project is 4.2 billion (British Petroleum 2006).
Health and Safety Assessment
The concern for health will be addressed in three categories listed below.
Worker Health and Safety
It is anticipated that between 1000 to 2000 workers will be deployed in the project. Extensive safety training will be given to each worker prior to a contract commencement. In addition, the proper safety equipment will be supplied in accordance to the residents and international policies on the work safety. The reinforcement of safety procedures will be the responsibility of contracting companies and enforceable by the relevant government authorities (Wilkirson et al. 1988).
The anticipated products will be natural gas and oil. Natural gas is harmful if inhaled and combustible if exposed to heat with a product spectrum of varying ignition temperatures. To contain the product, the proper control measures with regard to domestic use will be employed. Excess gas will be burnt under the controlled environment within the project jurisdiction, with a minimal gas leak to the environment. The project expects to utilize all gas produced either for re-injection to oil basin, pumping for a commercial use as a liquefied component in the oil pipeline, and for a domestic use in the surrounding communities (Jones 1971).
The nature of the machinery used may pose some safety concerns for the residents. As a result, the total area of project will remain out of bound for local residents, unless in special circumstances where an entry permit will be granted with a due caution for the safety enhancement.
Social Impact Assessment
The Prudhoe Bay project is to be carried in a remotely inhabited neighborhood, separated from major natural settlements. The Prudhoe Bay is listed as a Census Designated Place under the United States, with the total area of 1445 square kilometers and being the home to more than 2000 people. None of these populations will be in the operational jurisdiction of the project unless by the formal employment. This means that no displacement or obstruction of normal undertakings of the members will be foreseen.In addition, it is anticipated that as many as 1500 workers may be moved into the project area for the duration of the project, expected to span several decades. There will be a completely developed community infrastructure for the exploring and produced company’s personnel, with no strenuous relation with the immediate society (British Petroleum 2006).
This provision will require the arrangement for health, sanitation, recreation and any other facilities as may be necessary for workers by contracting firms during the project life.In the event of interaction with the resident communities, all forms of dealings will be governed by local authorities with the jurisdiction over Prudhoe Bay as directed by the United States Government.The project will strive to enhance the community’s wellbeing in the area, and though a direct employment of residents in the project may be subject to safety and skill based regulations, the project will seek to partner with the communities in such development initiatives as a gas supply for home lighting and heating, educational institutions and infrastructure (British Petroleum 2006).
Environmental Impact Assessment
The nature of products of the project is of the following varying environmental impacts.
The components in this product are combustible to give carbon dioxide or carbon monoxide, water vapor and energy. The carbon products are a danger to ozone, especially carbon dioxide. In the small domestic uses, the amounts of carbon dioxide so dispensed will be containable. However, the huge volumes of natural gas will pose a serious threat to ozone if the burnt onsite as is a tradition in the oil mining industry. For this concern, the project will seek to purify the huge volumes of surplus gas so obtained after the re-injection and to transport them in the oil pipeline for a commercial sale using such modern methods as the Gas to Liquid (GTL) method. Any remaining gas will be treated with certain chemicals to form the stable compounds for a safe disposal (“Gingrich and Knock & Masters” 2001).
Pipeline leaks pose the biggest immediate threat to the environment. Proper installation measures will be taken to ensure a sustainable containment of product lines and mines, including the use of standard installation pipes and equipment as regulated by the industry standards. In addition, the regular and efficient monitoring of corrosions and leaks will be done. Environmentally, the project is acceptable with some proper safety considerations and enforcement (Gingrich and Knock & Masters 2001).
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