Factors confronting the application of surfactant flood in high temperature, high salinity carbonate reservoirs include: high concentration of divalent ions in the formation brine, the stability of the surfactant in high thermal environment, surfactant adsorption on carbonate rock fabrics and the effect of high salinity and brine mineral composition on the multiphase system, typically encountered in carbonate reservoirs. For preliminary screening purposes, thermal stability, salinity tolerance and emulsification characteristics are given importance, while the capacity to alter the wettability of the reservoir rock towards a water-wet system is desired.
Several surfactants were screened based on their abilities to address issues of high thermal environment, high salinity effects and capacity to create a water-wet environment. A series of akyl-polyglucoside (APG) surfactants were studied which are established as eco-friendly, renewable, nontoxic and bio-degradable surfactant and one of them found to be suitable for the target carbonate reservoir. An unique approach adopted during the screening process for thermal stability was the analysis of the UV-visible light absorption profile of the surfactants after subjecting them to reservoir condition for specific periods. The APG showed salinity tolerance up to 263,000 ppm at 220 oF. During phase study divalent ions are seen to have considerable impact on the nature of microemulsion (middle phase). Incremental recovery between 19-15% was observed for surfactant flood after secondary waterflood and spontaneous imbibition of aqueous phase was enhanced in the presence of surfactant solution. The recovery was correlated with microemulsion phase behavior and wettability alteration.
Omar, Shaziera (Universiti Teknologi Malaysia) | Jaafar, Mohd Zaidi (Universiti Teknologi Malaysia) | Ismail, Abdul Razak (Universiti Teknologi Malaysia) | Wan Sulaiman, Wan Rosli (Universiti Teknologi Malaysia)
The natural pressure in hydrocarbon reservoirs is only sufficient in producing small amount of hydrocarbon at the end of the depletion stage. Therefore, in order to enhance or increase the hydrocarbon recovery, water or other fluids are injected into the formation to extract the hydrocarbon from the pore space. This common practice is known as Improved or Enhanced Oil Recovery (IOR or EOR). Foam is purposely used in some of the EOR displacement processes in order to control the mobility ratio, hence improving the volumetric sweep efficiency.
The efficiency of a foam displacement process in EOR depends largely on the stability of the foam films. In laboratory, foam stability is usually measured through physical observation of the foam bubble in a glass tube. Unfortunately, this direct observation is not possible in the reservoir. Therefore, indirect measurement such as the measurement of electrokinetic signal would be a better alternative. This study aims to determine the correlation between the foam stability and the associated streaming potential signals which resulted from the flowing fluid in foam assisted water alternate gas (FAWAG) process.
The experimental work will be conducted at the Reservoir and Drilling Engineering Laboratories at the Faculty of Petroleum and Renewable Energy Engineering (FPREE), UTM. The investigation includes sample preparation, sample analysis, displacing fluid formation, rheological properties test and electrokinetic signal measurement by using NI Data Acquisition System (NIDAS). It is expected that the burst of the foam bubble will change the pattern of the electrokinetic signals.
The research findings could lead to a new approach in monitoring a FAWAG process. Application in the real field could benefit the oil and gas industry in term of making the EOR process more efficient and more economic.
CO2 is injected into mature reservoirs for both sequestration and EOR. The effect of CO2 flooding on asphaltene stability has been extensively addressed in literature. In contrast, asphaltene / water interaction has not received much attention in literature.
The objective of the paper is to address the asphaltenic oil recovery by water alternating CO2 injection (WACO2) and asphaltene/ions interaction. Different water compositions, such as synthetic seawater (SSW) and low salinity water (LSW), Na2SO4, MgCl2 ions, and ion free water (DW), are used. SO4-2 and Mg+2 ions were selected based on previous work on their interaction with chalk minerals and modifying the surfaces to more water wet. CO2 is injected in miscible mode within the WACO2 recovery process. For simplicity outcrop cores and model oil were used. Model oil consists of n-C10, 0.35wt% asphaltene (extracted from a Middle East crude oil) and natural surfactant (stearic acid, SA). The effects of water injection rates were also investigatd to address the oil recovery efficiency in the cores and assess the water/oil/rock interaction as a function of injection rates. Imbibition process with various water compositions was tested for cores unflooded and flooded with CO2. This is to address the effect of CO2 on the fluids interaction.
It was shown that higher oil recovery was obtained when Mg+2 solution was used as imbibing fluid after CO2 flooding compared to SO4-2 solution. The opposite was observed without the CO2 flooding where higher recovery was obtained when Na2SO4 solution was used as an imbibing solution compared to that with MgCl2 as imbibing fluid.
Shiau, Bor Jier Ben (University of Oklahoma) | Hsu, Tzu-Ping (University of Oklahoma) | Lohateeraparp, Prapas (University of Oklahoma) | Rojas, Mario R. (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Raj, Ajay (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Bang, Sangho (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
Current global demand for fossil fuel such as oil is still high. This encourages oil and gas industries to improve their effort of finding new discoveries, developing technique and maximizing recovery of their current resources including in low-permeability reservoir. Enhanced oil recovery (EOR) is a technique to enhanced ultimate recovery. Since technology has been continuously developed such as nanotechnology/nano-size material, EOR methods have improved. One of them is Nano-EOR that triggered great attention in last decade. Nanoparticles may alter the reservoir fluid composition and rock-fluid properties to assist in mobilizing trapped oil. Most of observation from lab-scale reported that it seems potentially interesting for EOR.
Since reservoir management is very essential for the success of all improved/enhanced oil recovery (IOR/EOR) methods, optimizing nanofluids concentration is a proposed reservoir management to maximize oil recovery using Nano-EOR in this paper. Low-permeability water-wet Berea sandstones core-plugs with porosity ranged 13-15% and permeability ranged 5-20 mD were tested. A hydrophilic silica nanoparticles with primary particle size 7 nm was employed without surface treatment. Nanofluids with various concentration ranged 0.01 - 0.1 wt.% were synthesized with synthetic saline water for optimizing study. The wettability alteration due to nanofluids was observed; coreflood experiment was conducted and compared its displacement efficiency.
The results observed a range of nanofluids concentration that could maximize oil recovery in low-permeability water-wet Berea sandstone. Although contact angle of aqueous phase decreases as nanofluids concentration increase which means easier of oil to be released but we observed that higher concentration (e.g. 0.1 wt.%) has a tendency to block pore network and will decrease or even without additional oil recovery.
This study provides if concentration of nanofluids has an important parameter in Nano-EOR and could be optimized to maximize oil recovery of low-permeability water-wet Berea sandstone.
Various techniques of Enhanced Oil Recovery (EOR) exist and amongst them water and gas injection are the most widely used. It has been shown that combining water and gas injection in a WAG (water alternating gas) scheme can result in additional oil recovery. Interest in WAG injection has increasingly grown in recent times with many reservoirs around the world now under WAG injection.
Numerical simulation of WAG requires reliable three-phase relative permeability and hysteresis data which are normally obtained from models available in commercial simulators. This paper utilizes core-flood experimental data from literature to investigate validity of these models.
The findings from this study provide evidence that different three-phase relative permeability models were found to behave differently giving varying recovery factors in a WAG simulation scheme. While the effect of irreversible hysteresis was studied, it was observed here that imbibition (stage I) and drainage (stage II) processes gave results that deviated from conventional hysteresis. Simulations were run with and without hysteresis for different three phase relative permeability models with different effects observed for the recovery factor.
The results of this work show that a good understanding of the three phase relative permeability model in use is very important for a more robust reservoir simulation model. Also, the effect of irreversible hysteresis in WAG injection should be adequately modelled in order to obtain reliable results. Lastly, the results reveal the importance of optimum WAG ratio for maximizing oil recovery by preventing a gas tongue forming at the top of the reservoir and a water tongue forming at the bottom of the reservoir.
The paper presents compositional simulation studies of miscible water-alternating-gas (WAG) flooding in stratified reservoirs with respect to compositional variation with vertical depth and temperature. Two series of fluid system were selected from fifth and third SPE comparative study for Reservoir-A and Reservoir-B respectively. The Reservoir-A is an undersaturated black oil reservoir and has initial gas-oil ratio (GOR) of 557 scf/stb. Meanwhile Reservoir-B is near-critical oil reservoir with initial GOR of 3519 scf/stb. The minimum miscible pressure (MMP) variation with depth was calculated using equation of state in both reservoirs. In this study, temperature gradient sensitivity is ranging from 10 to 30 oF per 1000 ft for both active and passive thermal gradient.
The existence of thermal diffusion in WAG process is also discussed. It is investigated that active and passive thermal gradient will give opposite composition variation trend. In active temperature gradient, the amount of light components will increase and heavy components will opposite with respect to depth. Unlike active thermal gradient, the gravity isothermal and passive thermal gradients segregate the heavy components toward the bottom.
The initial oil in place (IOIP) varies due to compositional variation which is again due to gravity and thermal gradients. These issues should be even more obvious when we have oil reservoir with higher GOR or near-critical reservoir. In these particular reservoirs, the presence of gravity and passive thermal gradients will decrease IOIP calculation whereas both reservoirs will have less C7+ components than in basecase. Otherwise, considering thermal diffusion effect by applying active thermal gradients will increase IOIP.
Several parameters were also evaluated during WAG process in both reservoirs such as: various hydrocarbon injection gases, cyclic injection scheme, WAG cycle and ratio, and reservoir heterogeneities. Therefore the effect of compositional variation due to gravity and thermal gradients can be conclusively evaluated.
Uribe Hidalgo, Carlos Andres (Universidad Industrial de Santander) | Munoz Navarro, Samuel Fernando (Universidad Industrial de Santander) | Oliveros Gomez, Luis Roberto (Universidad Industrial de Santander) | Naranjo Suarez, Carlos Eduardo (Ecopetrol S.A)
In order to determine the best operating scheme, and taking into account the increase in demand for oil and the need of increasing the recovery of existing fields, enhanced recovery techniques are an alternative to the oil industry.
In Colombia, the stratified deposits of heavy oil have become the focus of oil exploration with EOR methods, including the one which is conceptually evaluated in this paper. However, the production of these fields has been restricted to strata having considerable thickness, forgetting about certain amounts of hydrocarbons from thin strata, representing significant potential for increasing production and reserves.
In search of the best alternative for extracting heavy oil reserves are contained in thin strata reservoir, this paper shows the technical and financial evaluation of applying cyclic steam injection using horizontal wells in these fields, using the injectivity and the benefit of the location Horizontal wells, and viscosity reductions product with steam heating. To carry out this process, It was evaluated the effect of each operational and reservoir parameters. Subsequently, due to the uncertainty of the distribution of steam in the reservoir and the importance of heterogeneities in this effect, the numerical simulation was performed with homogeneous and heterogeneous models, comparing productive behavior of each stage, to determine the best model to use in optimizing operational parameters.
Once the best scenario was determined it was performed a sensitivity and process optimization, seeking operating conditions that showed the best results with cyclic steam injection in horizontal wells, for further financial analysis that would provide a comprehensive feasibility study .
Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.
Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.
The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.
Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.
As part of the development planning of an alternating water and gas injection scheme for Enchance Oil Recovery in the Bokor Field, a risk evaluation study was carried out to assess the likelihood of injection gas migration from the reservoir to the
seabed. This hazard was identified as a principal HSE risk to the platform installations by the Bokor Field development team. A work flow was constructed which involved the integration of geological and petrophysical based seal evaluations with
coupled fluid-stress geomechanical modeling of the depletion and injection processes over the life of the field to determine reservoir shale seal efficiency and gas leakage risks due to both hydraulic fracturing and fault reactivation. The coupled
geomechanical modeling process incorporated, not only the resulting pressure changes arising due to depletion and injection within the reservoir, but also utilized a consolidation scheme to model the imposed pore pressure changes within the
overburden arising due to stress transfer, and the subsequent dissipation of these excess pore pressures with time. Evidence of fault related gas migration in the geological past is seen by the presence of a shallow gas cloud identified on seismic data sitting above the crest of the structure. The scope of the study included the evaluation of this cloud on various vintages of seismic from 1976 to 2011 to determine whether the size and geometry of the gas cloud was related to previous field development.
The study clearly demonstrates the application of coupled geomechanical modeling in assessing surface and subsurface risks resulting from field development.