Rate transient analysis (RTA) plays a significant role in the research and development sector of petroleum industry to know about the reserves and physical properties of commercially expected hydrocarbon fluids of a petroleum field. In this research, to conduct a rate transient analysis study; reservoir properties, well properties and Production data over the year of 2007 from two gas producing wells, Well-07 and Well-10 of Habiganj gas field, Bangladesh were used. There are two gas zones in this gas field: upper gas sand (UGS) and lower gas sand (LGS). Only UGS was considered as a gas reservoir in this research work due to no producing well in LGS. Software FEKETE, F.A.S.T.RTA TM (version 4.5.1.277), IHS Inc. was used to conduct this research. The objectives of this research were to estimate gas initially in place (GIIP) and expected ultimate recovery (EUR) of Well-07 and Well-10, to determine permeability and skin surrounding each of these two producing wells. After completion of the analysis, the GIIP and EUR values of Well-07 were estimated to 435.082 billion cubic feet (Bcf) and 304.558 Bcf, and those of 475.242 Bcf and 332.67 Bcf of Well-10, respectively. Skin effect and permeability in the surrounding of each of these producing wells were amounted to 7.017 and 3.0396 millidarcy (md) for Well-07 and those of 7.014 and 2.7839 md for Well-10, respectively, by the end of the year of 2007.Keywords Rate transient analysis Á Habiganj gas field Á Typecurve analysis Á Decline curve analysis Á Gas initially in place Á Expected ultimate recovery Á Skin Á Permeability List of symbolsSkin effect due to well drilling and completion S PT Pseudo-skin factor resulted from reservoir open level S PF Pseudo-skin factor due to perforation r s

With increased environmental focus and sustainability, classical water-based EOR with surfactants or polymers meet larger implementation scepticism. This has increased the attention toward water-based EOR methods with low environmental impact and lower costs, such as Smart Water and alkaline flooding. Both methods are based on the establishment of alkaline conditions in the formation. Chemical interactions among the rock minerals, reservoir fluids, and injection brine can be reflected in the pH of the produced water. Thus, the scope of this work is to investigate the development and transportation of pH through porous media during 1) low salinity (LS) Smart Water flooding, and 2) alkaline LS (alk. LS) waterflooding. Outcrop sandstone cores were used in core flooding experiments. Several pH-screening tests were performed to study the pH development during waterflooding. The ability of LS and alk. LS injection brines to increase the pH in sandstone core material with different mineralogy was compared, and the effect of pH on oil recovery was confirmed in an oil recovery test. The results of the pH-screening tests by LS brine injection showed a potential for increasing the effluent LS water pH up to 2 units in comparison to its initial pH-value. The oil recovery test performed on the same core material showed almost 10% incremental oil recovery during LS flooding in secondary mode, in comparison with formation water (FW) flooding. pH-screening tests with alkaline LS brine injection showed low potential for extra alkalinity above that obtained by LS brine injection. Transportation of alkalinity through a mineral system with large surface area seemed to be challenging due to pH buffering from brine/mineral interactions as well as from chemical interactions involving inorganic cations from the formation water. Based on the experimental results, ion exchanges between rock minerals and injected water can influence the reservoir pH and induce the wettability alteration. These chemical interactions can result in both development and consumption of alkalinity depending on the type of injected brine and chemical reactivity of the minerals. It was concluded that an in-situ generation of alkaline conditions at the waterfront seemed to have larger potential for EOR purposes than transferring the alkalinity of the injected brine through the reservoir.

Summary Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater. Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW. The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content. Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW. PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which EOR effects can be achieved.

Ionic modification of injected brines (Smart Water EOR) has previously demonstrated great potential for wettability alteration in carbonates from initially mixed-wet toward more water-wet conditions. However, the efficiency of Smart Water application is temperaturedependent, which reduces its ability as a rock wettability modifier at low temperatures (below 100 °C). Moreover, at low temperature conditions, the acid number of crude oils tends to increase in the reservoir, causing a stronger oil wetting character and less water-wet initial conditions. This paper evaluates the wettability alteration potential of surface-active ionic liquids added to Smart Water to obtain a synergistic enhanced oil recovery effect in low-temperature carbonate reservoirs. [C 12 mim]Br, [C 12 Py]Cl, and [C 16 Py]Cl were formulated in Smart Water (SW0Na) and tested as wettability modifiers in mixed-wet carbonate chalk cores. Spontaneous imbibition oil recovery tests showed that the addition of [C 12 mim]Br and [C 12 Py]Cl can cause wettability changes, resulting in increased oil recovery compared to pure SW0Na brine at 90 °C. The highest incremental oil recovery in tertiary mode of 24.6 % OOIP was obtained using [C 12 mim]Br in SW0Na, followed by [C 12 Py]Cl in SW0Na with 22.4 % OOIP, and only 11.5 % OOIP was recovered by pure SW0Na brine. The potential for wettability alteration for carbonate rocks was further evaluated in viscous flooding tests using the best formulation from the results obtained in the spontaneous imbibition experiments ([C 12 mim]Br in SW0Na). The core flooding results showed an ultimate recovery of 79.3 % OOIP achieved in secondary mode injection. Despite the difference in the head groups of the cationic [C 12 mim]Br and [C 12 Py]Cl ionic liquids, both formulations showed abilities to desorb polar organic components of crude oil from the chalk mineral surfaces, thus improving the performance of Smart Water EOR at 90 °C.

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