The EOR techniques are employed to recover more oil from mature reservoirs after the primary and secondary oil production stages. Polymer flooding as a chemical EOR method involves adding polymer molecules in order to increase water viscosity. Increasing water viscosity will improve the mobility ratio of injected fluid to reservoir fluid toward a more favorable value. Therefore, vertical and areal sweep efficiencies are increased compared to typical water flooding. Polymer flooding will be most effective if applied in the early stages of a water flood while the mobile oil saturation is still high. Polymer is also a critical component when considering other chemical EOR technologies such as alkaline-polymer or alkaline-surfactant-polymer. The present study covers two main parts. In the first part, fundamental of polymer flooding as it related to experimental work and simulation are discussed. The challenge of polymer flooding applications in high temperature and high salinity (HTHS) environment is also discussed in this part. In the second part, the synergy of polymer with surfactant and alkaline as chemical enhancing oil recovery (CEOR) methods is discussed.
Oil and Gas Industry is a Multi-Billion Dollar Industry. Drilling a well is costly, right from exploration to drilling and production to Enhanced Oil Recovery (EOR). Nanotechnology has the potential to introduce revolutionary changes in several areas of the oil and gas industry, such as exploration, drilling, cementation, production, EOR, etc. Use of Nanotechnology in the cement slurry can also achieve solutions to some of the problems pertaining to oil well cementation. Nano-silica is a better alternative compared to conventional additives like calcium chloride and silica, because as compared to calcium chloride and silica, the amount of nano-silica to be added is very small. Nano-silica acts as a multi-functional additive. Upon addition of nano-silica to cement slurry, there is a decrease in the thickening time, an increase in the compressive strength, decrease in porosity and permeability within the cement and also a decrease in the fluid loss. Incorporation of nano-silica ensures proper cementation and greater integrity of the well. Nano-silica helps in decreasing the wait on cement (WOC) time and therefore reduces the overall capital cost. Nano-silica is highly recommended for deep offshore wells where high temperature and high pressure are often encountered. This paper discusses the behavior of Nano-silica at high temperatures and also reviews effects of Nano-silica on various properties of cement.
As a typical kind of lithologic reservoirs, reef reservoirs are generally featured by their large single-well reservoir thickness, good reservoir physical properties, and high gas well productivity. The Upper Permian Changxing Formation is an important natural gas exploration target in the Sichuan Basin, which hosts a large reef gas reservoir and is mainly distributed along the Kaijiang-Liangping Trough. Comprehensive analyses are implemented to investigate reservoir characteristics and identify controlling factors of reef reservoirs in Changxing Formation in the Eastern Longgang Area, Northeastern Sichuan Basin, including core, logging, and seismic data analyses. Changxing Formation reservoirs in the study area mainly occur in the reef-shoal complex, which are featured by wide distribution, large thickness and generally good physical properties. Reservoir rocks are dominantly composed of bioclastic dolomite and silty-fine dolomite (with grain phantom structure), while the main reservoir space consists of residual intergranular pores, intergranular dissolution pores, and karst vugs. In the seismic profiles, typical mound-shaped chaotic reflections can be clearly seen. It is suggested by the main reservoir development controlling factor analysis that the distributions of reef reservoirs are typically controlled by sedimentary facies belts, while the scale of the reef-shoal complex is determined by the pene-sedimentary micro-paleo-geomorphology. Dolomitization can not only significantly preserve the primary pores but also enhance the permeability of rocks. Moreover, karstification is the key to high-quality reef-shoal reservoirs.
A great breakthrough has been made on oil-gas exploration of the Middle Devonian Guanwushan Formation in Northwest Sichuan Basin. The further exploration shows that the dolomite reservoir is complicated with insufficient investigation. Taking the Middle Devonian Guanwushan Formation as an example, systematic study has been carried out on its reservoir character, mechanism and genesis of dolostone. The field and core data suggest that reservoir types of Guanwushan Formation consist of crystalline dolomite, breccia dolomite and reef dolomite, and reservoir space is characterized by intercrystal (dissolution) pores, residual pores among breccias, intragranular dissolution pores, pockets as well as fractures. Besides, pore structure is of good configuration, showing medium-low porosity and moderate permeability, with average porosity and permeability of 2.23% and 0.44mD respectively, which suggesting fracture-pore and fracture-cavity reservoir. Combined with the previous research, it is suggested that the reservoir of Guanwushan Formation was controlled by facies, dolomitization and two-step karstification, with reef-shoal facies being material base for reservoir development, early dolomitization being key factor for reservoir space preservation, polyphase karstification being foundation for reservoir development and tectogenesis finally finalizing the reservoir.
Enhanced Oil Recovery (EOR) processes aim at increasing the performance and operative life of oilfields while newer, greener and more efficient energy sources are developed. Among the chemical EOR techniques, surfactant flooding is one of the most well-known methods, applied mainly in low-and medium-viscosity oilfields. Surfactants diminish the interfacial energy between the oleous and aqueous phases, reducing the forces responsible of the capillary trapping phenomenon and mobilizing the remaining oil. This paper presents the study of a novel two-dimensional surfactant flooding simulator for a four-component (water, petroleum, chemical, salt), two-phase (aqueous, oleous) system in porous media. It is aimed mainly at discussing the influence of the physical phenomena present in the reservoir during the recovery, namely: rock compressibility, diffusion, capillary pressure and adsorption. The system is numerically solved using a second-order finite difference method using the IMPEC (IMplicit Pressure and Explicit Concentration) scheme. The oil recovery factor was negatively affected when these phenomena were considered, being strongly sensitive to the adsorption. The other phenomena decreased the efficiency of the process to a lesser extent, whilst the capillary pressure did not affect significantly the flooding performance. The presence of salt in the reservoir rendered the adsorption process more relevant, with water-in-oil emulsions being more sensitive to the presence of this fourth component. This paper shows the importance of the design and optimization of chemical agents to be used in EOR before its field application.
The riserless mud recovery (RMR) system abandons the riser used in conventional offshore drilling, and the drill string above the seabed is directly exposed to seawater, resulting in convective heat transfer from the drilling fluid in the drill string to seawater. Therefore, the wellbore temperature distribution in the RMR system is quite different from the conventional offshore drilling. In this paper, based on the heat transfer characteristics of the RMR system, a mathematical model of the thermal field of the RMR system is established. The data used in this paper come from a vertical well in the South China Sea. Computational Fluid Dynamics (CFD) software is used to simulate the temperature distribution in drill string at different seawater depths and different formation depths in this paper, and the simulation results are compared with the calculation results of the mathematical model, so as to verify the feasibility of the mathematical model established in this paper. Combined with the calculation results of the mathematical model, this paper also explores the effect of different discharge capacity and different injection temperature of drilling fluid on the wellbore temperature change.
Pulsed neutron-neutron (PNN) logging is based on emitting neutrons into the near-wellbore zone and computing the neutron count decay due to scattering and capturing. The main application of this logging tool is to determine the current oil saturation and to detect channeling in perforated and non-perforated intervals behind the casing. Correct interpretation of the results obtained from PNN logging enables engineers to predict new perforation intervals in depleted reservoirs. This study examines the application of PNN logging in a well located in one of Iranian oil reservoirs. The interpretation procedure is described step by step. The principle of the PNN logging and the specifications of the tool are discussed and the applications of PNN logging in evaluation of oil saturation, identification of water flooded zones and prediction of potential perforating zones are described. Channeling is also investigated between all layers, good and poor oil zones are characterized based on the calculated oil saturations and new perforation intervals are suggested with the aim to boost oil production from the reservoir. The results of this study show that zones 1 to 5 having low oil saturations, are interpreted as depleted oil zones. Zones 6 to 8 are interpreted as good oil zones having high potential to produce oil. Zone 9 is interpreted as a water zone.
Compared with water-based well treatment fluid systems, hydrocarbon-based fluids possess advantages such as better fluid compatibility and lower formation damage, especially in water-sensitive formations. Hydrocarbon-based fluids are therefore often used in oilfield operations including hydraulic fracturing, sand control, and coiled tubing cleanout. The metal-crosslinked, phosphate ester-based gelled hydrocarbon (or gelled oil) fluids have been the preferred choice among hydrocarbon-based fluids since they are cost effective, robust at elevated temperatures, and operationally simple as only a couple of fluid additives are involved. Functioning as the gelling agent in gelled oil fluids, phosphate ester could cause fouling in refinery equipment. It is therefore desirable to lower the dosage of the phosphate ester-based gelling agent as much as possible, but without adversely affecting the fluid performance. A number of materials have been identified that could enhance the gelled oil viscosity and stability, which in turn translates into the reduction of the phosphate ester needed in the gelled oil. Among these enhancing materials, a type of aluminum pillared montmorillonite clay (the additive) was found to enhance the gelled oil viscosity to the largest extent. In laboratory tests, 30 ppt (30 pounds per thousand gallons) of the additive increased the gelled oil viscosity by 84% (± 5%) at 250 °F when compared with the baseline gelled oil without the additive. With the additive dosage at 30 ppt, the amount of the phosphate ester in the gelled oil could be reduced by 25% without decreasing the fluid viscosity. The additive was successfully applied to the crude oil-based gelled fluid, resulting in multiple times of viscosity increase in the study. In addition to the gelled oil viscosity enhancement, the additive also increased the regained permeability in the coreflow tests to near 3 times.
Asphaltenes removal enhances the quality of the oil and facilitates the processing. In the present work, a NiO/AlPO-5 nanocomposite using green TMG was synthesized as a particular adsorbent for asphaltenes removal. NiO/AlPO-5 was characterized using FTIR, BET, TEM, and XRD techniques. The Response Surface Method was used to optimize three important independent operating parameters, including D/C0 [(g)adsorbent/(mg/L)initial] (X1), initial pH (X2) and temperature (X3), to remove asphaltenes by the NiO/AlPO-5 nanocomposites in a model oil solution. Applying a CCD, a quadratic mathematical model formula was obtained to calculate asphaltene removal. The results revealed that the model showed valid agreement with the experimental results, with R2 = 0.94. The optimum values for D/C0, pH as well as temperature would be 0.08 [g/(mg/L)], 3.39 and 298 K, respectively. It was revealed that the optimal asphaltenes removal was 83.73% at the optimum point. The isothermal models of Langmuir and Freundlich represented the asphaltenes adsorption on the new adsorbent with acceptable accuracy.
To aid the magnetic anomaly detection (MAD) of underground ferromagnetic pipelines, this paper proposes a geometric modeling method based on the magnetic dipole reconstruction method (MDRM). First, the numerical modeling of basic pipe components such as straight sections, bends and elbows, and tee joints are discussed and the relevant mathematical formulations for these components are derived. Next, after analyzing the function of MDRM and various element division strategies, the sectional division and blocked division methods are introduced and applied to the appropriate pipeline components to determine the volume and center coordinates of each element, establishing the general models for the three typical pipeline components considered. The resulting volume and center coordinates of each component are the fundamental parameters for determining the MAD forwarding of underground ferromagnetic pipelines using the MDRM. Finally, based on the combination and transformation of the basic pipeline components considered, the visualized geometric models of typical pipeline layouts including parallel pipelines, pipelines with elbows, and a pipeline with a tee joint are constructed. The results demonstrate the feasibility of the proposed method of geometric modeling for the MDRM, which can be further applied to the finite element modeling of these and other components when analyzing MAD data. Furthermore, the models with output parameters proposed in this paper establish a foundation for the inversion of MAD.
During the past years, the recovery of unconventional gas formation has attracted lots of attention and achieved huge success. To produce gas from the low-permeability unconventional formations, hydraulic fracturing technology is essential and critical. In this paper, we present the development of a three-dimensional thermal-hydraulic-mechanical numerical simulator for the simulation of hydraulic fracturing operations in tight sandstone reservoirs. Our simulator is based on integrated finite difference (IFD) method. In this method, the simulation domain is subdivided into sub domains and the governing equations are integrated over a sub domain with flux terms expressed as an integral over the sub domain boundary using the divergence theorem. Our simulator conducts coupled thermal-hydraulic-mechanical simulation of the initiation and extension of hydraulic fractures. It also calculates the mass/heat transport of injected hydraulic fluids as well as proppants. Our simulator is able to handle anisotropic formations with multiple layers. Our simulator has been validated by comparing with an analytical solution as well as Ribeiro and Sharma model. Our model can simulate fracture spacing effect on fracture profile when combining IFD with Discontinuous Displacement Method(DDM).
This paper extends the analysis of the fourth model of Exploration and Production Sharing Agreement (EPSA IV) and our proposed modification of the Libyan Exploration and Production Sharing Agreement (LEPSA I) to field applications. The paper focuses on risk evaluation and analyzing the sensitivity of the fiscal terms of EPSA IV model (cost recovery, A factors, and B factors) and the fiscal terms of LEPSA I model (initial production share, the geologic probability of success, and the oil reference price) on the profitability indicators of Net Present Value (NPV) and Internal Rate of Return (IRR). The deterministic analysis method and stochastic analysis method using the Monte Carlo Simulation have been used in this study. The two methods were used to show the probability distribution of the NPV and IRR on the basis of the random variables of fiscal terms in the two models of EPSA IV and LEPSA I, respectively. The simulation output of the development field scenario of enhanced oil recovery using CO2 injection showed that the cost recovery is a very sensitive term on the NPV and IRR in the EPSA IV model. But, the A and B factors in the EPSA IV model have different sensitivities on the NPV and IRR. The B factor 3 and B factor 1 are more sensitive on the NPV and IRR than are other factors. The B factor 4 and A factor 4 have shown less effect on the NPV and IRR than the other factors. Moreover, the simulation output showed that the initial share and reference price are more sensitive to the NPV and IRR than the probability of success on the basis of the LEPSA I model.