This chapter concerns the use of water injection to increase the production from oil reservoirs, and the technologies that have been developed over the past 50 years to evaluate, design, operate, and monitor such projects. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir's natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil. The principal reason for waterflooding an oil reservoir is to increase the oil-production rate and, ultimately, the oil recovery. This is accomplished by "voidage replacement"--injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. The water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics).

Kirkuk is a supergiant oil reservoir located in Iraq. Kirkuk began production in 1934, and 2 billion bbl of oil were produced before water injection was implemented in 1961. From 1961 to 1971, 3.2 billion bbl of oil were produced under pressure maintenance by waterdrive using river water. The 1971 production rate was approximately 1.1 million barrels of oil per day (BOPD). Since then, the field has continued to produce large volumes of oil by voidage-replacement water injection; however, few production details for recent years appear in the technical literature.

Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.

Horizontal wells are being employed in innovative ways in steam injection operations to permit commercial exploitation of reservoirs that are considered unfavorable for steam, such as very viscous oils and bitumen and heavy oil formations with bottomwater. This page discusses some of the ways in which horizontal wells have been used to enhance steamflooding. Numerous papers have explored steam injection using horizontal- vertical-well combinations by use of scaled physical models or numerical simulators. For example, Chang, Farouq Ali, and George[1] used scaled models to study five-spot steamfloods, finding that for their experimental conditions, a horizontal steam injector and a horizontal producer yielded the highest recovery. Figure 1 shows a comparison of oil recoveries for various combinations of horizontal and vertical wells and for four different cases: homogeneous formation, 10% bottomwater (% of oil zone thickness), 50% bottomwater, and homogeneous formation with 10% pore volume solvent injection before steam.

This chapter concerns gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see the chapter on miscible flooding in this section of the Handbook. A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the United States[1] and Bahrain field in Bahrain[2][3]). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. Reasons for this range of performance are discussed in this chapter. At the end of this chapter, a variety of case studies are presented that briefly describe several of the successful immiscible gas injection projects. Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available.

Many aspects of reservoir geology interplay with the immiscible gas/oil displacement process to determine overall recovery efficiency. Because there is always a considerable density difference between gas and oil, the extent to which vertical segregation of the fluids occurs and can be taken advantage of or controlled is critical to the success of gas displacing oil. As with any oil recovery process involving the injection of one fluid to displace oil in the reservoir, the internal geometries of the reservoir interval have a controlling effect on how efficiently the injected fluid displaces the oil from the whole of the reservoir. The stratigraphy of a reservoir is determined primarily by its depositional environment. First and foremost is how layered the reservoir is in terms of both how heterogeneous the various sand intervals are and the scale at which shales or other barriers to vertical flow are interbedded with the sands.

TCP is a strong, noncorrosive, spoolable, lightweight technology which is delivered in long lengths, resulting in a reduction of transportation and installation costs. TCP is installed using small vessels or subsea pallets, significantly reducing CO2 emissions. It is also 100% recyclable. Strohm secured a contract with Total and ExxonMobil for a qualification-testing program for a high-pressure, high-temperature (HP/HT) thermoplastic composite pipe (TCP). The qualification project will create a foundation for further development of this TCP technology for riser applications.

Asia’s biggest oil refiner, Sinopec Corp, has announced its completion of Phase 1 of the Weirong development, a new shale-gas field in southwestern Sichuan province and China’s second largest. Located between the cities of Neijiang and Zigong in the southeastern quadrant of Sichuan, Weirong produces 3.5 million cubic meters (Mcm)/D and boasts an annual production capacity of 1 Bcm per year, according to Sinopec. Proven reserves are said to total 124.7 Bcm at an average well depth of 3,750 m. Sinopec said it drilled 56 wells attached to eight drilling platforms in the first phase of development, which began in late 2019. The state-owned major will now proceed with Phase 2 with plans to boost Weirong’s annual output capacity to 3 Bcm in 2022, a level of production believed to be sufficient to cover the fuel demands of 16 million households.

Production has started on the Mahani field in Concession Area B of the Sharjah Emirate, the first startup from a new discovery onshore Sharjah in 37 years. Italian energy major Eni and the Sharjah National Oil Corporation (SNOC) made the announcement on 4 January, less than 2 years from contract signature and 1 year since announcing the partnership’s first onshore discovery. Eni said it will continue its commitment on Sharjah exploration in operated area A and underexplored area C, with the aim of securing further resources for the Sharjah Emirate. Field production is expected to increase progressively with the connection of wells to be drilled this year and next. A strategy update from Eni said the Mahani would produce 18,000 BOED gross in 2022, giving it an equity share of 9,000 BOED.

Egypt’s Minister of Petroleum and Mineral Resources Tarek El Molla has signed nine new agreements worth more than $1 billion with six international and Egyptian companies to search for oil and natural gas in parts of the Mediterranean and Red Sea. The agreements are for the drilling of 17 new exploration wells. Three additional agreements are pending approval in the near future. The total of 12 deals target the drilling of 23 wells in nine regions in the Mediterranean and three regions in the Red Sea, with a minimum total investment of $1.4 billion. The first seven agreements, all signed by Egyptian Natural Gas Holding Co. (EGAS) are as follows.