This paper presents horizontal well test design and interpretation methods. New analytical solutions are developed, which can be easily handled by a desktop computer, to carry out design as well as interpretation using semi-log and log-log analysis. These analytical solutions point out a distinctive behavior of horizontal wells which is :- At early time, a circular radial flow in avertical plane perpendicular to the well.- At late time, a horizontal pseudo-radial flow. Each type of flow is associated with a semi-log straight line to which semi-log analysis has the adapted. The horizontal pseudo-radial flow takes into account a pseudo-skin depending on system geometry which is a priori defined and estimate Practical time criteria are proposed to determine Practical time criteria are proposed to determine the beginning and the end of each type of flow and provide a guide to semi-log analysis and well test design. We study the behavior of uniform flux or infinite conductivity horizontal wells, with wellbore storage and skin. The homogeneous reservoir is infinite or limited by impermeable or constant pressure boundaries. pressure boundaries. A method is also outlined to transform all our solutions for homogeneous reservoirs into corresponding solutions for double porosity reservoirs. 1 - Introduction The first horizontal producing wells yielded extremely positive results These results made it necessary to study flow around a horizontal well with a view to practical applications : test design and interpretation. The purpose of this study is to provide, with a horizontal well configuration a way :- to decide upon whether a test has to be made ornot : will the test help to obtain the requiredinformation ?- to optimize test time, if necessary : test mustbe long enough to be interpreted.- to interpret the test performed usingapplicable methods. The simplest and most significant analytical approach is first described in this paper. It relates to the transient behavior of a well with no wellbore storage C and no skin S, with a uniform flow (flow per unit length is the same everywhere in the well). Then the wellbore storage, the skin and the effect of the boundaries of the reservoir are taken into account, leading to a practical approach applicable to most real cases. The transposition of these solutions to infinite conductivity wells is described.

A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost. In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks. The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.

Summary An experimental study of polymer flooding is presented here, focusing on the influence of initial core wettability and flood maturity (volume of water injected before polymer injection) on final oil recovery. Experiments were performed using homogeneous Bentheimer Sandstone samples of similar properties. The cores were oilflooded using mineral oil for water-wet conditions and crude oil (after an aging period) for intermediate-wet conditions; the viscosity ratio between oil and polymer was kept constant in all experiments. Polymer, which is a partially hydrolyzed polyacrylamide (HPAM), was used at a concentration of 2,500 ppm in a moderate-salinity brine. The polymer solution was injected in the core at different waterflood-maturity times [breakthrough (BT) and 0, 1, 1.75, 2.5, 4, and 6.5 pore volumes (PV)]. Coreflood results show that the maturity of polymer injection plays an important role in final oil recovery, regardless of wettability. The waterflood-maturity time 0 PV (polymer injection without initial waterflooding) leads to the best sweep efficiency, whereas final oil production decreases when the polymer-flood maturity is high (late polymer injection after waterflooding). A difference of 15% in recovery is observed between early polymer flooding (0 PV) and late maturity (6.5 PV). Concerning the effect of wettability, the recovery factor obtained with water-wet cores is always lower (from 10 to 20%, depending on maturity) than the values obtained with intermediate-wet cores, raising the importance of correctly restoring core wettability to obtain representative values of polymer incremental recovery. The influence of wettability can be explained by the oil-phase distribution at the pore scale. Considering that the waterflooding period leads to different values of the oil saturation at which polymer flooding starts, we measured the core dispersivity using a tracer method at different states. The two-phase dispersivity decreases when water saturation increases, which is favorable for polymer sweep. This study shows that in addition to wettability, the maturity of polymer flooding plays a dominant role in oil-displacement efficiency. Final recovery is correlated to the dispersion value at which polymer flooding starts. The highest oil recovery is obtained when the polymer is injected early.

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

This screening study has been applied on a group of offshore carbonate oil reservoirs. The methodology is based on the EOR screening criteria set forth by Taber et. al. 1,2 enriched with additional screening criteria. The EOR techniques screened included solvent flooding (miscible, immiscible hydrocarbon and CO2 Gas flooding), chemical flooding (Polymer flooding, and Surfactant and Polymer flooding), as well as Thermal flooding (Steam injection and In-situ combustion) techniques. The screening study investigated the challenging and the killing parameters of each technique if any, indicating the most applicable EOR technique.By comparing the depth and API gravity data of the reservoirs under study to that of the worldwide producing EOR projects, it was possible to define at a glance which EOR methods have been already experienced for the same conditions of reservoir depth and API oil gravities. Furthermore, by considering the relatively high pressure and temperature of the heterogeneous carbonate reservoirs under study, with its low viscosity oil, and the associated high salinity formation water, several EOR methods can be discarded including: Steam Injection, In Situ Combustion, and Polymers. Two methods were found to be most suitable for most of the reservoirs: Miscible Hydrocarbon and CO2 Gas injection. Minimum Miscibility Pressure (MMP) has been estimated using correlations. A miscible gas injection could be achieved in most of the reservoirs by adding 2 to 13% C3-C4 to processed gas. CO2 mimimum miscibility pressure, MMP, is expected to be about 1000 psi lower than most of the reservoir pressures, making CO2 miscible flooding to be easily achieved.Surfactant Polymers flooding could reduce Remaining Oil Saturation in reservoirs with more than 50mD permeability. This technology is less mature, than other EOR technologies. It is yet too challenging due to the high salinity, high temperature and carbonate formation.