Water sample were collected from six different point of the Mouri River Khulna, Bangladesh with a regular intervals in the months of January-March 2002 for the analyzing different physicochemical parameters of the water. Total 22 different physicochemical parameters were investigated. Correlation and the t value among the parameters were also determined. In the present investigation the minimum and maximum value of water temperature, Transparency, Turbidity, TSS, TDS, Electric Conductivity, water pH, dissolve oxygen, free Carbon dioxide, Alkalinity, Acidity, Hardness, BOD, COD, Sulphate, Phosphate, Nitrite, Sodium, Calcium, Potassium, Manganese and Iron were noted as 21.6 and 32.2 degrees C; 15 and 66 cm; 16 and 22 NTU; 74 and 125 mg L(-1); 255 and 305 mg L(-1); 159 and 275 microS cm(-1); 1.10 mg L(-1) 8.18 mg L(-1); 7.5 and 8.3; 1.1 and 8.3 mg L(-1); 27.5 and 35.5 mg L(-1); 350 and 610 mg L(-1); 32.4 and 171 mg L(-1); 310 and 529 mg L(-1); 13 and 31 mg L(-1); 290 and 365 mg L(-1); 42046 and 57.35 mg L(-1); 4.89 and 11.46 mg L(-1); 0.54 and 1.82 mg L(-1); 16.8 and 33.9 mg L(-1); 1.5 and 6.9 mg L(-1); 49 and 94 mg L(-1); 31 and 59 mg L(-1); 2.6 and 3.8 mg L(-1), respectively. River water did not show any significant pollution during the present study. During the study period dissolved oxygen show direct relation with water temperature but inverse with BOD and COD.

While polymer flooding has widely been used as a successful technology to improve mobility control and sweep efficiency in many oil reservoirs, its applicability under harsh temperature/salinity conditions and in low-permeability reservoirs has prohibitively remained a challenge. This study was aimed at investigating the feasibility of low-salinity polymer flooding in a very challenging reservoir located in Kuwait with low permeability (< 10 mD), high temperature (113°C), high salinity (~239,000 ppm), high hardness (~20,000 ppm), and carbonate mineralogy. The evaluation was conducted through a series of systematic laboratory studies including polymer rheology, thermal stability, and transportability using coreflood tests. Our results highlight that the common constraints may be overcome by careful selection of polymer/cosolvent/pre-shearing and appropriate design of low-salinity polymer flooding.

This study presents an approach to exploit full potentials of a production logging run. In the proposed methodology, we seek layer flow contributions, reservoir parameter estimation, and well-performance optimization, in one logging operation. In particular, we match the entire wellbore pressure, temperature, and density profiles using a fully transient wellbore/reservoir simulator. In the proposed approach, perturbations can be created either from static or dynamic well condition. New formulations for these initial conditions for multirate tests with non-Darcy skin are presented. Field examples illustrate the notion presented in this work. P. 107

There are many oil reservoirs worldwide with substantial amount of H2S but otherwise very favorable conditions for polymer flooding such as low temperature, high permeability, and moderate to high oil viscosity. However, there is a legitimate concern about the chemical stability of polymers when there is dissolved oxygen in the injection water or injection facility and its high concentrations of H2S in the reservoir. Several synthetic polymers and biopolymers were selected for stability testing under a wide range of conditions. We focused on identifying the concentration limits for co-presence of H2S and oxygen for which the synthetic and biopolymers are stable for an extended period, using different, widely available brine compositions. Experiments were conducted with and without standard polymer protection packages to evaluate their effects on stability and degradation under sour conditions. Viscosity of polymer solutions with varying concentrations of H2S and oxygen were measured and compared with the oxygen free or H2S free solution viscosities for a period of 6 months. Several methods of safely introducing H2S to the polymer solution were investigated and compared. The laboratory results indicated that biopolymers were stable at all the concentrations of oxygen and H2S concentrations studied. Three synthetic polymers tested showed some degradation in the presence of oxygen and H2S but were stable when either species is absent. The results indicated that oxygen is the limiting reagent in the degradation reaction with partially hydrolyzed polyacrylamide (HPAM) polymers under normal reservoir conditions. We observed little-to-no difference in degradation between samples with 10 or 100 ppm H2S at 500 ppb oxygen concentration, so H2S is not the limiting reagent under these conditions. Additionally, HPAM exposed to 10 ppm H2S and intermediate levels of oxygen (~0.5 ppm) only partially degrades, while samples exposed to H2S and ambient oxygen completely degrade. We anticipate these results will be useful for operators evaluating the potential of polymer flooding in sour reservoirs to follow a stricter polymer preparation at the surface facility to minimize oxygen concenration.

Waterflood oil recovery in many carbonate oil reservoirs is low due to both high residual oil saturations and low sweep efficiency because of high heterogeneity. An example is the Sabriyah Mauddud reservoir in Kuwait. Alkaline-surfactant polymer flooding (ASP) has great potential for enhanced oil recovery both because ASP flooding reduces residual oil saturation and because of the polymer improves sweep efficiency. Unfortunately, the initial ASP coreflood experiments using conventional alkali showed unacceptably high surfactant retention in the reservoir cores. Several approaches to reducing surfactant retention were tested. Numerous strategies such as the use of chelating agents, sacrificial agents and chemical gradients were tested to reduce retention. The most effective strategy used a hybrid-alkali (NaOH + Na2CO3) in addition to a hydrophilic polymer drive containing a novel co-solvent. In this approach injection pH was increased to 12.5, compared to 10.5 using only Na2CO3. Such high pH is undesirable in sandstones because of reactions with silica minerals, but theexperimental results described here suggest the process is suitable for carbonate reservoirs. With this approach, both low surfactant retention and high oil recovery were achieved in very tight reservoir cores (8-35 mD). This novel approach was validated in a live oil coreflood using preserved cores to represent the reservoir material in the most rigorous way possible. This significant decrease in surfactant retention makes ASP flooding in the Sabriyah Mauddud reservoir viable.