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The Kuparuk River oil field is west of the supergiant Prudhoe Bay oil field on Alaska's North Slope and was discovered in 1969. It has approximately 5.9 billion bbl of stock tank original oil in place (STOOIP) and covers more than 200 sq. The sandstone reservoir consists of two zones [A (62% of STOOIP) and C (38% of STOOIP)] that are separated by impermeable shales and siltstones. Sales oil is approximately 24 API with a viscosity at reservoir conditions of approximately 2.5 cp. The reservoir oil was approximately 300 to 500 psi undersaturated at the original reservoir pressure of approximately 3,300 psia.
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
When the CEO of Occidental Petroleum described the company's future this week, it was clear the company will not be moving away from hydrocarbons. By 2050, Occidental expects to still be a big oil company, but producing oil and natural gas is not likely to be its biggest source of revenue. Several decades from now, Vicki Hollub, the president and chief executive officer of Occidental, predicted that income from carbon capture and storage "will be bigger than oil production revenue." During the plenary session for the Unconventional Resources Technology Conference (URTeC) she described how Occidental is scaling up its carbon-capture business, beginning with a facility in the Permian Basin with the capacity to capture 1 million tons of CO2 per year. First announced by Occidental in early 2019, design is in progress with construction expected in 2023. The planned capacity is 250 times greater than any such plant in existence and will be an early test of the economics of large-scale carbon capture.
In formations where the pore space is occupied by a stationary gas phase and a mobile water phase, such as in a watered-out gas reservoir, the residual gas saturation (Sgr) may need to be measured in situ. The Sgr also can be determined using a single-well injection/production test method. Sgr measurement involves injecting and immediately producing a suitable volume of water. The water used for injection typically is produced from the target well before the test and stored in tanks on the surface. During production, the amount of gas dissolved in the water (Rsw) that is produced from the formation is measured.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
A successful well to well tracer test is more than selecting the right tracer. It involves determining the appropriate timing, designing the field test, and collecting and analyzing the samples. A well designed sampling program will produce high quality tracer-response curves for further interpretation. The timing for tracer injection depends on the information that is requested. Normally, it is desirable to inject the tracer early in the injection process to obtain information as soon as possible and be able to take the necessary actions to optimize the production strategy.
Miscible injection is a proven, economically viable process that significantly increases oil recovery from many different types of reservoirs. Most miscible flooding projects use CO2 or nitrogen as solvents to increase oil recovery, but other injectants are sometimes used. This page provides an overview of the fundamental concepts of miscible displacement. Also provided are links to additional pages about designing a miscible flood, predicting the benefits of miscible injection, and a summary of field applications. Fieldwide projects have been implemented in fields around the world, with most of these projects being onshore North American fields.
While enriched hydrocarbon projects are less frequent, these types of projects have been very successful miscible floods when adequate supplies of methane and enriching fluids are available and profitable to inject. The permotriassic-aged Ivishak (also known as Sadlerochit) reservoir, the largest producing horizon in the field, is a series of clastic zones ranging from near-shore marine deposits in the lower sections to sandstones and conglomeratic braided-stream deposits in the remaining, more productive units that contain most of the original oil in place (OOIP). The productive area is 225 square miles. The reservoir is a structural stratigraphic trap consisting of a faulted, south- and southwestward-dipping, 1 to 2 homocline. The main and western areas contain gas caps with different gas/oil contacts (GOCs).
Petroleum reservoir management is a dynamic process that recognizes the uncertainties in reservoir performance resulting from our inability to fully characterize reservoirs and flow processes. It seeks to mitigate the effects of these uncertainties by optimizing reservoir performance through a systematic application of integrated, multidisciplinary technologies. It approaches reservoir operation and control as a system, rather than as a set of disconnected functions. As such, it is a strategy for applying multiple technologies in an optimal way to achieve synergy. Reservoir management has been in place in most producing organizations for several years.
In many operations worldwide, surface waters are injected into producing formations to enhance oil recovery. The types of surface waters used range from seawater (salt water) to lake water (brackish) to river water (fresh water). Surface water must be treated to remove undesirable components before injection. Treatment of surface water for injection requires a specially designed system made up of various components to remove or control any contaminants in the water. The system is engineered to perform the required treatment in the most cost-effective and environmentally sensitive manner. A typical system is shown in Figure 1. Commonly used methods for removal or control of these contaminants are discussed in this section. Surface waters normally contain suspended solids particles that, if injected into the producing formation, will plug the injection well. The type, concentration, and particle-size distribution of suspended solids in water will vary depending on the source of the surface water.