Current water management strategies require recycling and reuse of oil sand process affected water (OSPW) to as much as 80%. Continuous recycling and reuse of OSPW degrades water quality as the concentrations of total dissolved solids (TDS) and dissolved organic materials (DOM) accumulate. This results in a net increase in operating and maintenance costs and an impact on the extraction process and bitumen recovery. Remaining water containing fines and suspended clays adds to the mature fine tailings and associated problems for tailings pond treatment and management. Presence of residual bitumen and other organics is known to create difficulties in common practices for flocculation and dewatering of tailings. With the problems stated above, one may consider a pre-treatment approach rather than the common post-treatment remedies.
The ore grade profoundly affects the efficiency of bitumen recovery in the hot water extraction of bitumen, the principal step in the bitumen extraction process. Sodium hydroxide is commonly added to the conditioning step to improve bitumen recovery. As the sodium ions build in concentration, they disperse clays in the ore and create tailings that resist dewatering. This is especially true for low-grade and oxidized ores, which present the greatest challenges in bitumen recovery and produce the major portion of tailings due to high fines content. With current trends for increasing production from mining operations to almost double by 2020, industry has to adopt new technologies to manage tradeoffs between water and energy.
We present a new approach toward total water management by introducing environmentally friendly process aids that can improve bitumen recovery from low-grade oil sands ores. Lab-scale experimental data from a Denver flotation cell and hydrotransport loop were analyzed to evaluate the efficiency on the processability of high and low grade oil sands, water chemistry and tailings management. The results demonstrate that using new process aids during the conditioning stage improves bitumen recovery from low-grade oil sands and can accelerate tailings settling. This pretreatment approach can be incorporated into current oil sands mining processing facilities and delivers environmental and economical benefits. A critical evaluation for use of new process aids versus sodium hydroxide is given in detail.
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.
High molecular weight polyacrylamides are key components in oil recovery, particularly in the stimulation, production, and enhanced oil recovery of oil and gas wells. These polymers can be divided into three broad classes based on their physical state: dry polyacrylamides (DPAMs), emulsion polyacrylamides (EPAMs) and solution polyacrylamides (SPAMs). While the molecular weights of these polymers can range from 1 million to more than 30 million Daltons, molecular weight is limited by physical state. In general, EPAMs can reach higher molecular weights and consequently exhibit better performance than DPAMs and SPAMs. However, standard EPAMs exhibit poor freeze tolerance and irreversible inversions, while DPAMs suffer from extremely slow dissolution rates and require additional capital expenses such as makedown and storage equipment.
Next-generation winterized EPAMs have been developed that are capable of withstanding temperatures down to -35 °C without freezing. These polymers invert rapidly, reaching complete dissolution within 60 seconds in fresh water, hard water, and other concentrated brines, allowing for higher throughput and overall energy savings. The new EPAMs were compared to commercially available EPAMs used in friction reduction and EOR applications. The emulsion stability was assessed by freeze-thaw and rheological measurements, while stimulation and EOR performance were characterized using a friction loop and core flooding apparatuses. These next-gen EPAMs demonstrate values for viscosities, shear resistance, inversion times, freeze tolerance, and filterability that make them superior to commercially available dry and emulsion polyacrylamides. Furthermore, these polymers are formulated to be environmentally friendly and readily biodegradable.
A family of emulsion polymers has been developed that exhibits low-temperature tolerance, increased dissolution rates and biodegradability without sacrificing EOR and stimulation performance in various brines. The modular nature of these products has led to the creation of a flexible polymer platform that allows for customizing products for specific application needs.
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.
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 (HPAMs) are the major class of polymers used for chemical EOR application. However, due to the high flexibility of HPAM 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.