Constant Composition Expansion Tests Research Articles

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

A modified gas flow model in the near wellbore region below dew point pressure

When pressure in gas reservoirs fall below the dew point, condensate banking occurs around the wellbore which alters the fluid flow behavior. The state of the knowledge on this flow behavior is yet not fully-developed; which leads to severe problems in field. In this study, the Al-Hussainy, Ramey, and Crawford Solution Technique has been modified to accurately resemble the real gas flow behavior for this condition. First, a primary investigation was conducted to observe the severity of the problem in three condensate banked reservoirs. Then this study involved Constant Composition Expansion tests for determining the dew point, Prode Properties software for modeling the reservoir fluid properties, Flowing Material Balance (or Dynamic P/Z Material Balance) for identifying the pressure distribution of the selected reservoirs. The real field data along with the determined (analytical, computational, and experimental) data were incorporated to check the validity of the models. The modification proposes a Dimensionless Correction Factor (CD) for any condensate banked reservoir and identifies parameters such as the Perforation Factor (Pf) and Heterogeneity Factor (n). It is found that the Modified Al-Hussainy, Ramey, and Crawford Solution Technique successfully models the actual flow characteristics of the stated condition.

CO2 injection strategies for enhanced oil recovery and geological sequestration in a tight reservoir: An experimental study

Considering the worldwide development of tight and ultra-tight oil reservoirs, the increasing demand for fossil energy and long-term environmental concerns regarding large CO2 emissions, application of dual-purpose carbon dioxide (CO2) sequestration/enhanced oil recovery in oil reservoirs has gained considerable attention [1,2]. However, unlike its mature application in conventional reservoirs, the effectiveness of CO2 EOR and geological sequestration in tight reservoirs is still under investigation [3]. In this work, we investigated the efficiency of different injection strategies on simultaneous CO2 EOR and storage in ultra-low permeability (<1 milli-Darcy) [4] core samples from Yanchang Formation in the Ordos Basin, China. Three injection strategies were tested including gas continuous flooding, water alternative gas injection, and cyclic gas injection. Core-flooding experiments under immiscible and miscible conditions were conducted. Furthermore, to investigate underlying mechanisms of oil recovery and carbon storage in tight cores, interfacial tension tests, viscosity measurements, contact angle measurements, and constant composition expansion tests were performed using reservoir rock and fluids. We found that water alternative gas injection was superior to continuous gas injection in achieving the goal of simultaneous high oil recovery and high CO2 storage. However, cyclic CO2 injection provided the most efficient strategy for enhanced oil recovery in the tight rocks studied in this work with a comparatively higher gas storage capacity than the other injection strategies.

A novel visualization approach for foamy oil non-equilibrium phase behavior study of solvent/live heavy oil systems

In this study, a novel visualization methodology to study solvent non-equilibrium exsolution behavior in heavy oil systems is proposed. A Hele-Shaw-like visual cell with adjustable aperture depth, has been designed to overcome the shortcomings of traditional apparatuses such as a hardly-visual PVT cell, or non-visual transfer cylinders. By eliminating the 3D nature of the traditional apparatuses, the true 2D bulk phase visual cell can directly visualize the interface evolution of foamy oil under pressure depletion. Totally, 6 sets of Constant Composition Expansion tests (CCE) were conducted with a CO2-C3H8-heavy live oil system. The effect of pressure depletion rates on solvent non-equilibrium exsolution behavior have been tested. Meanwhile, the initial volume fill-up percentage of live oil in the visual cell was also found to have an effect on foamy oil generation and endurability. This helps to define the appropriate volume of live oil to be saturated in PVT tests that aim to induce non-equilibrium. Through analyzing the deviation of liquid/vapor phase volume fraction from equilibrium state, non-equilibrium regimes of solvent exsolution were effectively found. The experimental design is also able to continuously capture the real-time solvent component exsolution sequence during pressure depletion. Numerical simulation of solvent non-equilibrium exsolution behavior has been conducted by a MATLAB-controlled reservoir simulator with real-time optimization. By dynamically adjusting the K value in the simulator, the total flashed vapor phase volume and the individual solvent component mass was history-matched. The achieved non-equilibrium K values were compared with equilibrium K values, and a delayed solvent exsolution was indicated.

Experimental study on foamy oil behavior using a heavy oil‒methane system in the bulk phase

In this study, three types of constant composition expansion tests on foamy oil are conducted in a pressure/volume/temperature cell: (a) constant pressure depletion rate test, (b) constant volume withdraw rate test, and (c) step-by-step test. The experiments are conducted to investigate the effect of pressure depletion methods and depletion/withdraw rates on a heavy oil‒methane system in bulk phase. Pure methane is recombined into a typical Manatokan dead heavy oil sample to generate a live oil sample. Totally, nine experiments are undertaken including four experiments for the constant pressure depletion rate test, four experiments for the constant volume withdraw rate test, and one experiment for the step-by-step test.New foamy oil behavior, which is presented as relative volume changes of foamy oil over time, is researched in this study. The experimental results indicate that similar trends and phenomena are investigated for both constant pressure depletion rate test and constant volume withdraw rate test. For solution gas phase, the concentration of solution gas has a strong exponential relationship with time. In addition, the reaction rate constant kSG which indicates the gas transfers rate from solution gas to dispersed gas, increases with the depletion/withdraw rate increases. For free gas phase, moles of the evolved free gas proportional to t1/2, and the same relation is observed in step-by-step test. Furthermore, the pseudo-bubble point pressure decreases with the depletion/withdraw rate increases, and a new approach using the trendlines of the moles of free gas versus t1/2 is developed to determine the time when the pseudo-bubble point pressure achieves.

Experimental and modeling study of CO2 - Improved gas recovery in gas condensate reservoir

Abstract This paper presents the effectiveness of the CO 2 injection process at different periods during gas-condensate reservoir development. Taking a real gas-condensate reservoir located in China's east region as an example, first, we conducted experiments of constant composition expansion (CCE), constant volume depletion (CVD), saturation pressure determination, and single flash. Next, a series of water/CO 2 flooding experiments were been investigated, including water flooding at present pressure 15 MPa, CO 2 flooding at 25.53 MPa, 15 MPa, which repents initial pressure and present pressure respectively. Finally, the core flooding numerical model was constructed using a generalized equation-of-state model reservoir simulator (GEM) to reveal miscible flooding mechanism and the seepage flow characteristics in the condensate gas reservoir with CO 2 injection. A desirable agreement achieved in experimental results and predicted pressure volume temperature (PVT) properties by the modified equation of state (EOS) in the CVD and CCE tests indicated that the proposed recombination method can successfully produce a fluid with the same phase behavior of initial reservoir fluid with an acceptable accuracy. The modeling results confirm the experimental results, and both methods indicate that significant productivity loss can occur in retrograde gas condensate reservoirs when the flowing bottom-hole pressure falls below dew point pressure. Moreover, the results show that CO 2 treatment can improve gas productivity by a factor of about 1.39 compared with the water flooding mode. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

Nonequilibrium Phase Behavior of Alkane Solvent(s)–CO2–Heavy Oil Systems under Reservoir Conditions

A pragmatic technique has been developed to experimentally and theoretically quantify the nonequilibrium phase behavior of alkane solvent(s)–CO2–heavy oil systems under reservoir conditions. Experimentally, constant-composition expansion tests have been conducted for alkane solvents–CO2–heavy oil systems at constant-volume expansion rates with a PVT setup to simultaneously measure volume and pressure change of the aforementioned systems. Theoretically, mathematical formulations have been developed to quantify the amount of the evolved gas as a function of time based on the real gas equation, while mathematical models on compressibility and density of the oleic phase mixed with the entrained gas (i.e., foamy oil) are respectively formulated. The required equilibrium time and exponential coefficients associated with gas-bubble growth are determined once the deviation between the experimentally measured pressure–volume profile and the theoretically calculated one has been minimized. In addition to effectivel...

Experiments and Modeling of Volumetric Properties and Phase Behavior for Condensate Gas under Ultra-High-Pressure Conditions

Four reservoir samples under ultra-high-pressure and high-temperature conditions were collected from condensate gas fields in China. Constant-composition expansion tests were performed to determine the phase behavior and volumetric properties of reservoir fluid using an ultra-high-pressure fluid PVT test system. The compressibility factor and dew-point pressure were obtained at four temperatures for four samples. The range of pressure was from 22.03 to 118.89 MPa. For the samples studied, the experimental results showed that the dew-point pressure decreased with increasing temperature and the compressibility factors increased with increasing pressure but decreased with increasing temperature at a given high reduced pressure. A thermodynamic model based on an equation of state was developed to describe the volumetric properties and phase behavior of the condensate gas under ultra-high-pressure conditions. The calculated results are in good accordance with the experimental data, which is important for the d...