Enhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions.
Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ios at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery.
The objective of the work presentd here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92°C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO42- is lower in the smart water, the occurrence of SO42- as anhydrite in carbonates may be sufficient to stimulate a similar reaction between the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system.
Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO42-, Mg2+ and Ca2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.
Bustos, Ulises Daniel (Schlumberger) | Salazar Barrero, Giovanni (Pacific Rubiales Energy S.A.) | Aldana, Ivan (Pacific Rubiales Energy S.A.) | Moreno, Wilson (Pacific Rubiales Energy S.A.) | Zamora, Henry (Pacific Rubiales Energy S.A.)
Colombia’s Oil production is around 1.1 million barrels per day (bpd), where 57% is from Heavy Oil fields. Current oil recovery is in the 15% to 17% range; with targets to increase it up to 50% through different methods. A typical reservoir exhibits hydrocarbon viscosity variations in hundred of centipoises, with formation water salinity typically below 5000 ppm and heterogeneities driving a complex fluids distribution. Since the low amount of salt in these environments prevents low frequency conductive devices for contrasting water versus hydrocarbons, where additionally, resistivity profiles are ambiguous to assess fluids mobility in the reservoirs.
In this context, the incorporation of additional physics of measurements opens a new perspective in the reservoir evaluation in Llanos basin, by reducing uncertainties and helping in the initial reservoir characterization. The new generation of wireline measurements supporting the present job is represented by multifrequency dielectric propagation, radial magnetic resonance and dynamic testers, in addition to the conventional triple combo logs.
Since good-oil bearing rocks (high porosities and permeabilities, very clean sands, high oil saturations) do not guarantee oil production (very high water cut is likewise common), the identification of movable oil and free water volumes in low salinities is mandatory. Understanding its distribution across sands is also a critical factor in heavy oil environments.
As a resistivity and salinity-independent reservoir evaluation approach, the combination of dielectric dispersion and radial magnetic resonance, provides a valuable sensitivity for the evaluation of displaced oil, free and irreducible water, viscosity and rock quality variations. Dielectric Dispersion is the variation of relative permittivity and conductivity versus frequency, enabling pore fluids determination. With a dielectric analysis at two depths of investigation, integrated with NMR-based diffusion mesurements, a direct identification of movable oil under filtrate invasion conditions and free water presence is achieved.
The correlations encountered between the dielectric dispersion is encouraging; whereas a better understanding on the movable oil occurrence and estimation of the fluid to be moved during production is achieved. Discussions with case studies in Llanos Basin are presented in this paper.
The operating plan generation of a reservoir is based on an effective dynamic characterization for recovery of reserves. To achieve this goal we must prepare, the model describes the interaction between the rock and the fluids present in the reservoir, as well as contributing to the achievement of the original reserves in place, facilitates the reproduction of the behavior of a reservoir to be undergone some enhanced recovery process. For this reason it was necessary to develop a methodology for determination of critical water saturation according to the size of Throat Poral by capillary pressure analysis performed on core samples of the fields belonging to developed areas of the Orinoco Oil Belt. In this study we propose a methodology that combined with the little information that may exist in a specific area leads to a better use of that information as a representative model of the entire stratigraphic column. These results can then be used as input for reservoir simulation models belonging to these fields, allowing the representation of heterogeneity present in the same anisotropy obtaining a representative distribution of the fluids and with this a more accurate estimation of reserves hydrocarbons and their movement within the reservoir, and generating operating plans with excellent results in the estimated potential wells. In this case the method used yielded a correlation of critical water saturation as a function of pore throat radius, with an adjustment of 90% with respect to laboratory measurements.
Proper well construction involves long-term integrity; thus, accurate characterization of the physical properties of set cement systems is mandatory. Chemical stability, compressive strength, and permeability are commonly the main parameters determined for oilfield cement systems. The knowledge of these properties is most often enough to estimate if a cement system will maintain well integrity. However, some hydrocarbon recovery processes are highly aggressive toward the cement sheath. Under thermal processes for recovery of heavy oil, such as steam-assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS), the well temperature can reach up to 350°C. The casing expands during the heating-up phase, and this outward expansion increases the stress on the annular cement sheath. Under such conditions, simulations show that a key intrinsic thermal property, the linear coefficient of thermal expansion (LCTE), is equally as important as the other physical properties to maintain well integrity.
To determine the LCTE of set cement, one needs to understand the thermal-expansion theory of solid materials. An experimental setup for measuring this parameter for set cement has been developed, and essential precautions for performing accurate measurements have been formulated.
The LCTE of cement is a critical parameter in the development of new cement technologies for high-temperature (HT) well applications; the chemical composition of the cement system and the curing conditions can affect the LCTE of oilfield cement systems.
Improved understanding of this critical parameter has allowed significant improvement of the reliability of cement systems used in these hostile environments and provides better solutions in the form of thermally responsive cement systems.
One of the most important tasks in Petroleum Engineering is the characterization of the properties of the reservoirs for the application of the method that will bring a greater oil recovery factor. Among the different special recovery methods with great potential for improving the oil recovery factor, the foam injection can be mentioned. The foam may be used as a selective block agent of the reservoir, which reduces the effective permeability zones already swept with high permeability. A widely used tool for this purpose is the simulation of petroleum reservoirs, which through the application of numerical methods allows for the solution of the hydraulic diffusivity equation.
Hoyos Perdomo, Ruben Dario (Universidad Industrial de Santander) | Ardila Cubillos, Lexly Jhoanna (Universidad Industrial de Santander) | Munoz Navarro, Samuel Fernando (Universidad Industrial de Santander) | Rincon Canas, Maria Monica (Universidad Industrial de Santander) | Palma- Bustamante, Jorge Mario (Ecopetrol SA) | Naranjo Suarez, Carlos Eduardo (Ecopetrol SA)
Steam injection is one of most successful techniques for improving oil recovery in heavy oil fields. However some reservoirs have characteristics that are not adequate for the implementation of this technique due to reservoir heterogeneity, where steam driving is present in most favorable areas as a result giving a channeling which does not allow the existence of a uniform vertical steam distribution, leaving unheated areas, decreasing the process efficiency and obtaining unexpected oil recovery factors. Therefore in this paper different strategies were evaluated using a numerical reservoir simulator to determine most suitable option with the greatest chance of technical success for the implementation of selective steam injection. For the development of this research initially a study of selective steam injection process was performed in stratified reservoirs, once it was made this, the strategies for selective injection were raised: Steam injection at maximum and minimum rates for different layers, the product of each layer permeability by thickness and reservoir stimulation preceded by selective injection. Finally, the strategies selected were implemented in conceptual simulation models built in this case for a stratified homogeneous and heterogeneous reservoir developed with the properties of a Colombian heavy oil field using a comercial software. The final results were analyzed based on the behavior of the oil recovery factor and the injection profile, these confirmed the efficiency of the technique, allowing to heat the formations by appropriate injection rate and for this reason an increase in the amount of recovered oil. After obtaining the simulation results is set the better or best possibilities for implementing selective injection, it determines the range of application where selective steam injection could be run efficiently obtained from the ratio of the product of the permeability by the thickness and it is determined that treatment is best for the reservoir with cyclic steam simulation before selective steam injection.
A significant number of naturally fractured reservoirs (NFRs) discovered in the world contain heavy and extra heavy oil. These reservoirs are important resources; however, the nature of naturally fractured reservoirs, especially those containing heavy and extra heavy oil, presents many unique and complex challenges for reservoir modeling and simulation. There have been a number of attempts over the last 50 years to develop methods to improve our understanding as to how the fracture systems impact oil recovery. For many decades, the dual-porosity approach has been the most popular and effective technique in modeling of NFRs. This approach separates the fracture and matrix systems into two different continua, each with its own set of properties. Fluid exchange between matrix and fractures is modeled through a Transfer Function (TF), while a shape factor describes the fracture-matrix surface area. However, the fracture-matrix fluid interaction is not yet fully understood for thermal processes, which represents a significant unknown in thermal reservoir simulation of NFRs containing (ultra) heavy oil.
In this paper an extensive literature survey was initiated to establish a detailed understanding as to how shape factors are utilized for modeling non-isothermal, fracture-matrix fluid exchange in fractured reservoirs. The most appropriate way is to treat the shape factor as a time-dependent quantity to capture the pertinent features of non-isothermal fluid flow in fractured reservoirs. A series of numerical simulations have been conducted using the simulator STARS from Computer Modeling Group Ltd. in order to analyze the performance of existing transfer functions and shape factor formulations for dual-porosity, multiphase flow systems in thermal reservoir simulation. Based on this analysis, we introduce the concept of a new, transient shape factor for non-isothermal, dual-porosity models and compare our new concept with the existing shape factor models. The results from this study clearly confirm that a transient shape factor is required for an appropriate modeling of a thermal recovery process in NFRs when using dual-porosity formulations.
In many countries, Heavy and Extra Heavy oil reserves are located in sensitive environments, remote from existing infrastructure. Heavy oil production is energy intensive, requiring the combustion of fossil fuels to produce the heat and power required. Burning fossil fuels creates a wide variety of emissions to atmosphere, such as the Carbon Dioxide (CO2) released by burning carboniferous fuels to combustion pollutants such as oxides of nitrogen (NOx). In addition, Heavy Oil reservoirs tend to be gas deficient, and often a low cost way of disposing of the small quantities of unwanted associated gas is to flare it, creating a new source of emissions.
The first part of this paper looks at how to minimise emissions from energy production by making best use of locally available fuels, such as associated gas, and employing energy efficient techniques such as Cogeneration. It then discusses how the three most common power generation technologies – gas turbines, reciprocating engines and steam turbines – can be applied to Heavy Oil operations to minimise the impact of fossil fuel combustion.
However, building and operating a power plant or energy facility of any kind, also has other impacts on the environment. There are transportation issues in getting the equipment to site in the first place, the human impact on the environment due to both construction and operation of facilities, the issue of disposal of produced wastes, and the need for continuous re-supply of the power plant with the consumable items and spare parts to keep it operational. This paper therefore also compares the consumable and maintenance needs of the three main power generation technologies to investigate the long term impact of operations on the environment.
Toelsie, Sharmila (Staatsolie Maatschappij Suriname NV) | Mohan, Amresh (Staatsolie Maatschappij Suriname NV) | Griffith, Cliff Rossano (Staatsolie Maatschappij Suriname NV) | Wong Fong Sang, Mark Anthony (Staatsolie Maatschappij Suriname NV) | Chin A Lien, Henk Sam Tsoi (Staatsolie Maatschappij Suriname NV)
As of February 2014, Staatsolie operates 1560 active wells mainly with Progressive Cavity Pumps (PCP) for artificial lifting of heavy crude oil of averagely 16oAPI. These pumps are installed at an average depth of 1000 feet, producing crude from unconsolidated Tertiary sand reservoirs. Average pump life time of 2 months up to 25 years have been realized with these PCP’s. Optimal operation of these PCP’s requires sufficient submergence in liquid to prevent the pump running dry and causing early failures. To achieve maximum pump life time, a minimum wellbore annulus liquid level between 50 to 100 feet above pump intake is applied to avoid partial cavity filling problems and dry running of the PCP.
The liquid levels in the wells are mainly acoustically surveyed. Significant challenges in well optimizations to achieve optimal well production conditions at the lowest submergence level were experienced with a foamy liquid column in the annuli resulting into apparent high flowing bottomhole pressure (FBHP). The application of downhole pressure gauges started in 2005 with the main objective to increase the reliability of actual FBHP based on downhole memory and surface read out pressure sensors. Main disadvantage of the memory sensors was the required well intervention jobs to retrieve the gauge to download the recorded data, while surface read out downhole pressure sensors had the advantage of real-time data availability. With the development in downhole pressure sensor applications, smart well operation was initiated in 2011. A smart well at Staatsolie operates around a preset target fluid level. This is achieved by automatic regulation of the pump speed via a variable frequency drive. Smart monitoring can be done locally as well as remotely through an online interface option. Both monitoring methods have the possibility of automatic shutdown control once enabled. The smart application focused mainly on the effective control of the PCP speed to prevent downhole pump failures caused by running dry of the pump and the possibility in achieving optimized production.
This paper intends to cover the experienced operational challenges, advantages and disadvantages based on the testing of different smart well technologies in the Staatsolie heavy oil fields.
This paper investigates the use of CO2 as an EOR solvent for a heavy oil and high permeability naturally fractured reservoir complex in Mexico. The complex is under partial pressure maintenance by Nitrogen injection. First geological features and production performance are analyzed to discern peculiar pressure trends caused by natural depletion and N2 injection in order to establish the nature of prevailing fluid communication and identify a confined site for CO2 injection testing. An East Block in the North fields due to its unique dynamic faulting characteristics is found nearly compartmentalized to serve as a suitable site for CO2-EOR injection studies. Second, a finely-gridded dual permeability compositional simulation sector model with local grid refinement and boundary flux scheme is constructed and a calibrated 8-component EOS along with full tensor molecular diffusion is implemented to model CO2-EOR process mechanisms. CO2 and N2 injections into the gas cap at varying rates and huff-n-puff injection in the oil column are simulated. The impact of injection rate is illustrated, where injection of CO2 at low rates promotes diffusion and is shown to drain more of the matrix oil. The huff-n-puff simulation cases also indicate increased oil recovery and reduced matrix oil saturation by CO2 injection as compared with N2 injection due to a combination of oil swelling, reduced oil viscosity and partial miscibility with CO2. The paper concludes that the efficiency of CO2 injections is more pronounced at higher reservoir pressures and with no or less volumes of prior injected N2.