The rheological characteristics of copolymers of acrylamide (AM) with sodium salt of 2-acrylamido-2-methylpropane sulfonic acid (PAMS), and of hydrolyzed polyacrylamide (HPAM) have been studied in both NaCl solutions and synthetic seawater. PAMS may possible have high salt tolerance and thereby find use in enhanced oil recovery processes for high salinity reservoirs. The viscosity and solubility effect of the PAMS copolymers have been systematically studied with variations in sulfonation degree and molecular weight. Emphasis has been studies as a function of shear rate, polymer concentration, NaCl and divalent ions concentration in aqueous phase. Shear rate dependence of PAMS varies with sulfonation degree, and PAMS with higher sulfonation degree is found to be less shear rate dependent. PAMS with high sulfonation degree are more salt tolerant also compared to HPAM. Also the effect of divalent ions on viscosity of PAMS is lower compared to HPAM. Two parameters will increase the solubility effect of the PAMS copolymers in mix brine, one is sulfonation degree and the other is in the presence of NaCl. Both parameters have a direct effect on the solubility of PAMS copolymer in mixed brine. In all cases the PAMS copolymers are more salt tolerant than HPAM.

ABSTRACT:The viscosity and retention of several copolymers of acrylamide (AM) with sodium salt of 2-acrylamido-2-methylpropane sulfonic acid (PAMS), and also hydrolyzed polyacrylamide (HPAM) have been studied under aerobic condition with and without the sacrificial agent, isobutyl alcohol (IBA) added at a temperature of 80 C. Parallel experiments have been performed in synthetic seawater (SSW) and 5 wt % NaCl. The viscosity at high temperature has been studied as a function of aging time, shear rate, sulfonation degree, molecular weight, and concentration of IBA. The retention in porous medium for sulfonated polyacrylamide polymers was measured in core floods using outcrop Berea sandstone. For the studied polymer sacrificial agent may protect polymer structure at high temperature. Higher sacrificial agent concentration gives better thermal stability in both 5 wt % NaCl and SSW solvents. Sulfonation degree also has a direct effect on thermal stability, i.e., higher sulfonation degree lead to better thermal stability in terms of viscosity. By increasing temperature, less relative reduction in polymer solution viscosity was observed for the polymer with lower molecular weight. The presence of divalent ions at high temperature leads to strong reduction of HPAM polymer solution viscosity, but the viscosity is better maintained for PAMS copolymer solution at high temperature. The precipitation of HPAM first occurred after 3 months at 80 C and for PAMS copolymer with lowest sulfonation degree precipitation started after 7 months. For the studied polymers the retention was found to be relatively independent of temperature and compared to HPAM a much lower retention is observed for the sulfonated copolymers.

A key parameter for application of polymers for water flood mobility control is the loss of polymer due to adsorption to the rock and more general retention during flow in porous medium. The paper discusses the adsorption and retention properties of sulfonated co-polymers. These polymers have the same backbone structure as partly hydrolyzed polyacrylamide (HPAM), except for modified hydrophobic groups and

Hydrocarbon liquid consists of a range of components with different physico-chemistry characterization. Sometimes there are heavy component with crude oil such as asphaltene, naphthenic and paraffinic wax components and etc. Deposition of wax in both onshore and offshore pipelines presents a costly problem in the production and transportation of oil. There are several parameters contributing to wax deposition in multiphase crude oil flow, e.g. pressure drop, flow rate, pipe internal body surface roughness, surface energy of the pipe, liquid wetting of pipe wall as well as temperature difference between fluid and surroundings [1,2]. Application of internal coating of subsea pipelines can reduce wax deposition. The aim of the present work is to experimentally study the wax deposition in Malaysian waxy crude oil, where the data set studied was gathered from several experiments. Most of the methods can be used to remove the paraffinic wax deposition after it occurs. However, insulation systems yielded in better performance as it was found to help in the prevention of heat loss and solid deposition during flow conditionsThis study utilized flow loop apparatus. This paper compared the wax deposition behaviour with temperature, roughness and flow rate within the tested pipes [Polyvinyl Chloride (PVC), Ethylene - TetraFluoroEthylene (ETFE), and steel as a reference material]. Moreover, the prevention of temperature loss from liquid to surrounding and corrosion control significantly affects pressure drop across the pipeline [3]. The conducted experiments concluded that ETFE had a better effect on the paraffin wax deposition control. Moreover, ETFE as a novel polymer based coating material was economically feasible to be utilized in the oil and gas downstream and upstream systems exposed to wax deposition.

No abstract

Power consumption of wellbore drilling in oil and gas exploitations count for 40% of total costs, hence power saving of WBM (water-based mud) by adding different concentrations of Al2O3, TiO2 and SiO2 nanoparticles is investigated here. A high-speed Taylor–Couette system (TCS) was devised to operate at speeds 0–1600 RPM to simulate power consumption of wellbore drilling using nanofluids in laminar to turbulent flow conditions. The TCS control unit uses several sensors to record current, voltage and rotational speed and Arduino microprocessors to process outputs including rheological properties and power consumption. Total power consumption of the TCS was correlated with a second-order polynomial function of rotational speed for different nanofluids, and the correlated parameters were found using an optimization technique. For the first time, energy saving of three nanofluids at four low volume concentrations 0.05, 0.1, 0.5 and 1% is investigated in the TCS simulating wellbore drilling operation. It is interesting to observe that the lower concentration nanofluids (0.05%) have better power savings. In average, for the lower concentration nanofluids (0.05%), power was saved by 39%, 30% and 26% for TiO2, Al2O3 and SiO2 WBM nanofluids, respectively. TiO2 nanofluids have better power saving at lower concentrations of 0.05 and 0.1%, while Al2O3 nanofluids have saved more power at higher concentrations of 0.5 and 1.0% compared with their counterpart nanofluids.

An API standard drilling fluid was investigated from laminar to turbulent flow conditions using an in-house-built viscometer at speeds from 200 to 1600 RPM. A power-based method was applied to obtain the apparent viscosity and the shear stress of the water-based drilling mud (WBM) in the annulus of the viscometer. Then, a MATLAB optimization program was developed to obtain model parameters for five rheology models integrated in a generalized Herschel-Bulkley-Extended (HBE) model and two widely used 4-parameter models in drilling industry. It is found that the Bingham, Cross, and HBE rheology models have precisely matched the WBM measurements in the viscometer. A generalized Reynolds number was applied to determine the Darcy friction factor although the PL (power law model) and the HB (Herschel-Bulkley model) exhibited a nonrealistic negative shift from the laminar friction factor.

No abstract