It is estimated that about 7,000 billion barrels of oil will remain in reservoirs after production by conventional methods. This value is the target for Enhanced Oil Recovery (EOR) techniques. The purpose of the water-soluble polymers in EOR application is to enhance the rheological properties of the displacing fluids. These polymers have been successfully implemented in China’s oilfields. Given the harsh conditions present in most oil reservoirs, new problems and challenges arise with the use of such polymers. Currently partially hydrolyzed polyacrylamides (HP AMs) are the major class of polymers used for chemical EOR application. However, due to the high flexibility of HP AM chain in aqueous solutions, particularly at high temperature (HT) and at high salinity (HS), the molecular chains begin to fold irreversibly resulting in a significant loss in viscosity. In this paper, we are reporting a bench-scale development of new PAM-based polymers with improved performance in HSHT conditions. The new polymers were evaluated conditions for their viscosity performance at various temperatures and salinities. The polymers were dissolved at different concentrations in brines with TDS (Total Dissolved Solids) of 34,655 ppm and 180,000 ppm. Viscosity measured at room temperature is in the range of 30 to 120 cP at the shear rate of 6 RPM. After aging at 90 °C and 120 °C for six months under ultralow oxygen level (< 5 ppb), viscosity remains relatively stable for some polymers while show a decline for others. Compared with the conventional HPAM polymers, these new polymers have much better stability at HTHS conditions.
Recent excavations at Kadakkarappally in Kerala, south-west India, have unearthed the remains of an iron-fastened boat, believed to predate the earliest known records for the use of iron in South Asian boatbuilding. The design departs significantly from the traditional view of Indian watercraft, although the use of locally available timber and the suitability of the design for use in the backwaters that characterise the region suggest that it was built and used in India. This is the first excavation of its type to take place in Kerala and contradicts the belief, widely held in Kerala, that the survival of organic remains has been negated by the tropical climate of the region.
Current technologies for in-situ heavy oil recovery involve either heating the reservoirs to liquefy the hydrocarbons or attacking the deposits with solvents. This is usually accomplished by providing a source of external energy such as using natural gas to heat the oil or subjecting it to mechanical stimulation. However, a challenging case is in ultra-shallow reservoirs where the recovery is limited only to matrix oil drainage by gravity. In these cases, many heavy oil reservoirs are too thin to use thermal processes for enhanced heavy oil recovery due to the heat losses to overburden and underburden. In this paper, a study to develop a new technology to increase heavy oil recovery using alkali, surfactant and polymer is presented. It has been found that novel surfactants can create a stable emulsion for heavy oil and formation brine, by which viscosity of heavy oil can be reduced significantly. At 25 °C, the viscosity of heavy oil is 15,785 cP. But when the heavy oil and synthetic brine are emulsified with some new surfactants, the viscosity reduces about 2.88 to 3.46 cP. Therefore, the mobility of heavy oil is improved significantly.In order to analyze the contribution of the various components to viscosity, a heavy oil sample was separated with a silica gel column. It was found that asphaltenes and resins, the two heaviest and most polar components in the heavy oil, exert the largest influence on the viscosity of heavy oils. Viscosity decreases as temperature increases, which is leveraged by thermal technology for heavy oil recovery. The decrease in viscosity is most pronounced, however, at temperatures below 60 °C. The high viscosity of heavy oil can be dramatically reduced further by emulsification with proper surfactants and alkali, which is the principle behind non-thermal technology for heavy oil recovery.In this research, emulsions created by the surfactants B and E are stable at 25 °C, and their performance in non-thermal heavy oil recovery was evaluated using sand pack flooding test. 23% of heavy oil recovery was achieved by injection of surfactant B and polymer Superfloc ® A-110 HMW. It has also been found that injection of 1.0 PV of surfactant solution followed by injection of 1.0 PV of polymer solution to be the optimum methods for both surfactants B and E. In most cases, Superfloc ® A-110 HMW polymer seems to be slightly better than Superfloc ® A-120 V for enhanced heavy oil recovery.
On average, 3 barrels of water is produced for every barrel of oil in offshore platforms. The water must be treated for reuse or discharge. Oilfield produced water contains a diverse mixture of compounds that varies from formation to formation. Of particular importance are the organic compounds classified as "Oil and Grease" (O&G) by the Clean Water Act. These compounds must be removed to meet environmental, political and operational goals. Excessive O&G in re-injected water can foul the equipment or the formation. Discharged water must meet legal or contractual standards often less than 30 mg/L per day. Governmental restrictions are put on the quality of water-discharge to sea, but the self-imposed corporate guidelines provided by the oil-companies are often more stringent. As a result a water treatment facility running smoothly is important, and a fitting control structure provided a good tuning strategy is essential in reaching this goal. When selecting produced water treatment technologies, one should focus on reducing the major contributors to the total environmental impact. These are dispersed oil and semi-soluble hydrocarbons, alkylated phenols, and added chemicals. Experiments with several samples of produced water from South America offshore platforms have been performed. These experiments were designed to find efficacy of treatment strategies using a combination of oxidation, coagulation and flocculation methods. Experiments were conducted at various pH values (6 – 9) with samples containing TOG of 17 – 198 mg/L and TSS of 100 – 1000 mg/L. With optimal and low dosage of coagulant/flocculant, oxidation process and treatment sequence, TOGs can be easily reduced to below discharge limit. Results from our studies indicate the viability of this approach for water management in offshore platforms with no need for capital equipment.
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