Soek, Harry (PDO) | Jaboob, Musallam Sunhail (Petroleum Development of Oman) | Singh, Maniesh (Petroleum Development of Oman) | Jabri, Ahmed Abdullah (PDO) | Stoll, Martin (Shell E&P International Ltd) | Faber, Marinus J. (Shell Intl E&P BV) | Harthy, Khalfan (PDO) | Al Mjeni, Rifaat (Petroleum Development of Oman) | Van Wunnik, John N.M. (PDO)
Vermolen, Esther C.M. (Shell International Ltd.) | Van Haasterecht, Menno J.T. (Shell International E&P Inc) | Masalmeh, Shehadeh K. (Shell Technology Oman) | Faber, Marinus J. (Shell Intl E&P BV) | Boersma, Diederik Michiel (Shell Intl E&P BV) | Gruenenfelder, Marc A. (SNF Oilfield Group)
This paper reports a laboratory study of a novel alkaline-surfactant-foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed AS formulation could meet the two key requirements for a good enhanced oil recovery (EOR), i.e. lowering the interfacial tension (IFT) considerably and ensuring a good mobility control. The study included phase behavior tests, foam column tests and CT scan-aided core-floods. It was found that the IFT of the designed alkali-surfactant (AS) and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and core-floods in absence of oil. The mobility reduction due to the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT scanned core-floods demonstrated that AS foam following a small AS pre-flush recovered almost all the oil left after water-flooding. The oil recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
Zwaan, Marcel (Shell Intl E&P Co) | Hartmans, Robert (PDO) | Saluja, Jasmeet Singh (Shell Intl E&P Co) | Schoofs, Stan (Petroleum Development of Oman) | Rocco, Guillermo (PDO) | Adawi, Rashid (PDO) | Saadi, Faisal (Shell Intl E&P Co) | Lopez, Jorge L. (Shell Global Solutions International) | Ita, Joel (Shell Intl E&P Co) | Mahani, Hassan (Shell Intl E&P BV) | Qiu, Yuan (Petroleum Development of Oman) | Rehling, Johannes
PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.
Because of progress in technology in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects.
The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through timelapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
In this work we consider model-based optimization of polymer flooding. The reservoir performance is optimized by finding for each injection well optimal values for control variables such as injection and production rates, polymer concentrations, and times when to switch from polymer to water injection (i.e. polymer grading). The same technique can also be applied to optimize other EOR processes such as for example designer water flooding, alkali-surfactant polymer (ASP) flooding and foam flooding. The optimization method that has been used relies on the adjoint implementation in our in-house reservoir simulator to efficiently calculate the gradients. The adjoint method enables the computation of gradients with respect to injection and production rates, injection compositions of each well and switching times of each well at the additional cost of approximately the computation time of a single reservoir simulation. The optimization method uses the adjoint-based gradients to estimate the values of all polymer injection control variables that maximize reservoir performance.
The optimization method is demonstrated on a full-field reservoir simulation model. The physics that is modeled includes polymer mixing, hydrodynamic acceleration of the polymer molecules and adsorption of the polymer to the rock. The example shows that the Net Present Value increases significantly as a result of the optimization, mainly due to increased oil production and decreased polymer injection. The obtained optimal control is physically interpreted, so that the learning points from the model-based optimization can be applied to the field and can be used to enhance the polymer flood.
Increasing oil production by injection of designer water - also known as low salinity water - into a reservoir has recently attracted substantial attention from the oil producing community. The phenomenon has been studied by many researchers and low salinity water flooding is currently being applied in the field. On a macroscopic level, the effect can be parameterized as effective wettability modification to a more water-wet state but on a microscopic level, the effect is still not very well understood.
Most researchers agree that in sandstone rock, the mechanism is related to clay minerals but most of the experimental evidence is provided on the macroscopic scale (core flooding experiments) or even the field scale. Observations are not fully consistent and the predictability of the effect is limited. In a preceding publication [Petrophysics 2010, 51(5), 314-322] direct experimental evidence was provided for the detachment of oil droplets from a clay substrate upon exposure to low salinity brine.
The brine salinity for designer water flooding falls within a narrow window of opportunity: when too high, no additional oil production is observed; when too low, clay swelling and/or deflocculation may result in formation damage in the field. This raises the question whether there is a regime where oil is released with no or only minor formation damage and what the optimum salinity level for this would be. In this follow-up study, experiments are conducted on montmorillonite clay (which is a swelling clay belonging to the group of smectite clays) where the amount of released oil and the degree of formation damage are studied as a function of the salinity level. Starting at very high salinity (26,000 mg/L totally dissolved solids, TDS) no release of oil was observed and the clays remained stable. At very low salinity (2,000 mg/L TDS), up to 30% of the oil was released accompanied by substantial formation damage. There is, however, an intermediate salinity regime between 6,000 and 15,000 mg/L TDS where the formation damage is only very minor or not visible at all and still 10-30% of the initially attached oil is released. This is the regime of interest for field applications, although salinity levels have to be evaluated for the type of clay present in the formation rock.
Andrianov, Alexey (Shell Intl E&P Co) | Farajzadeh, Rouhollah (Shell Intl E&P BV) | Nick, Mahmood Mahmoodi (Statoil) | Talanana, Mohand (Shell Global Solutions International) | Zitha, Pacelli L.J. (Delft U. of Technology)
This paper reports a laboratory study of foam for improving immiscible gas flooding. The study is relevant for both continuous and Water Alternating Gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. From the column experiments it was found that foam longevity increases as the carbon chain length in the oil molecule increases, i.e. foam is more stable for higher viscosity oils. A surfactant formulation that gave the most stable foam in the presence of oil was used in the core-floods. Oil recovery with CO2 and with N2 foams from natural sandstone cores was studied with the aid of X-ray Computed Tomography, varying the injection rates, foam quality and surfactant concentration. The core-floods revealed that foam increases the oil recovery by as much as 20% of the oil initially in place (OIIP) over water flooding while injection of gas increased oil recovery by 10% only. Thus, foam adds up to 10% additional recovery on top of gas injection. This confirms that foam is potentially an efficient Enhanced Oil Recovery (EOR) method.
Karpan, Volodymyr (Shell Exploration & Production) | Farajzadeh, Rouhollah (Shell Intl E&P BV) | Zarubinska, Maria (Shell Exploration & Production) | Dijk, Harm (Shell Intl E&P Co) | Matsuura, Tsuyoshi (Shell Exploration & Production) | Stoll, Martin (Shell E&P International Ltd)
In order to design and analyze Alkaline Surfactant Polymer (ASP) pilots and to generate reliable ASP field forecasts a robust scalable modeling workflow for the ASP process is required. A starting point of such a workflow is to carry out ASP coreflood tests and history match those using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for field-scale simulation forecasts.
It is well established that lowering of interfacial tension due to maximum of in-situ generated soap with injected surfactant and improved mobility control due to the polymer play a crucial role in the ASP process. Therefore, all models for the ASP process take into account these mechanisms in one way or the other. However, ASP models can differ in the detail in which (geo-) chemical reactions and the phase behavior are addressed. Inclusion of the more details into the numerical model could result in better understanding and more accurate prediction, but it comes at a price, viz., it requires more measured input data and increases computational time. Thus, depending on the accuracy requirements, available experimental data and time the modeling of ASP flood can be performed using different simulation approaches.
This paper describes several modeling approaches for ASP. We start with a brief description of these methods and their input requirements. Then we compare the ASP coreflood simulation results demonstrating the advantages and disadvantages of presented approaches. We also demonstrate that both ASP models can be applied at the field level by simulating an ASP flood in a sector model. Finally we give some recommendations and guidelines on how and when the proposed models should be used.
Alkaline/surfactant/polymer (ASP) flooding is an enhanced oil recovery (EOR) technique that involves the injection of a solution of surfactant, alkaline and polymer into the oil reservoir to mobilize the remaining oil. In this process the injected surfactant and the petroleum soaps generated in situ reduce the oil-water interfacial tension (IFT), improving the microscopic sweep efficiency (Nelson et al., 1984). Moreover, the macroscopic sweep efficiency is enhanced through improvement of the mobility ratio due to the injected polymer. Another important benefit of the alkali is the reduction of surfactant retention on the rock surface, allowing for the injection of smaller amounts of surfactant. Indeed, in some cases where the crude oil does not react with the alkali, the injection of alkali is recommended to prevent surface retention of expensive surfactant. As a further improvement, the addition of a co-solvent may enhance the combined solubility of the surfactant and the polymer in the injected ASP solution and reduce the viscosity of (micro-) emulsions formed when the ASP solution contacts the crude oil.
The ASP process is usually applied to tertiary floods in the drive mode. Because of the considerable costs of the chemicals associated with the ASP flooding, an ASP slug (a fraction of the reservoir pore volume) is generally injected, and then followed by a solution of a water-soluble polymer. Typical estimated incremental recoveries for ASP flooding after water flood are of the order of 10 to 20% STOIIP (Pitts et al., 2006, Qu et al., 1998, Vargo et al., 2000).
Accurate modeling of an Alkali-Surfactant-Polymer (ASP) flood requires detailed representation of the geochemistry and, if natural acids are present, the saponification process. Geochemistry and saponification affect the propagation of the injected chemicals and the amount of generated natural soaps. These in turn determine the chemical phase behavior and hence the effectiveness of the ASP process.
In this paper it is shown that by coupling the Shell in-house simulator MoReS with PHREEQC a robust and flexible tool has been developed to model ASP floods. PHREEQC is used as the chemical reaction engine, which determines the equilibrium state of the chemical processes modeled. MoReS models the impact of the chemicals on the flow properties, solves the flow equations and transports the chemicals.
The validity of the approach is confirmed by benchmarking the results with the ASP module of the UTCHEM simulator (UT Austin). Moreover, ASP core floods have been matched with the new tool. The functionality of the model has been also tested on a 2D sector model. The advantages of using PHREEQC as the chemical engine include its rich database of chemical species and its flexibility to change the chemical processes to be modeled. Therefore, the coupling procedure presented in this paper can also be extended to other chemical-EOR methods.
During primary and secondary recovery, as a result of interplay between gravity, viscous, and capillary forces, oil remains trapped in the reservoir pore structure. The remaining oil saturation in the reservoir is a function of the capillary number (Bedrikovetsky, 1993; Lake, 1989): the higher the capillary number the lower the remaining oil. The capillary number is usually defined as
where u is the Darcy velocity, µ is the viscosity of the displacing fluid, and is the interfacial tension (IFT) between the displacing and displaced fluids. The aim of the enhanced oil recovery (EOR) techniques is to decrease the remaining oil saturation by increasing the capillary number. Within realistic field rates this is possible by reducing the interfacial tension. Increasing the viscosity of the displacing fluid mainly affects the macroscopic sweep (mobility control) and does not
significantly impact the microscopic sweep.
Alkaline Surfactant Polymer (ASP) flooding is an elegant technology for mobilizing the remaining oil. In this process a slug containing alkaline, surfactant and polymer is injected into the reservoir and chased by a polymer drive. The surfactant lowers the interfacial tension between the oleic and aqueous phases. For crude oils containing natural acids the alkali has a dual purpose: it generates soaps, or natural surfactants, upon reaction with the acid (Johnson, 1972; Caster et al., 1981; deZabala et al., 1982; Ramakrishnan and Wasan, 1983; Porcelli and Binder, 1994) and reduces adsorption of the injected surfactants by inducing a negative charge on the rock surface (Hirasaki and Zhang, 2004). The polymer is added to provide mobility control and to improve the macroscopic sweep.