An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI

CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.

Comprehensive investigation of low salinity waterflooding in carbonate reservoirs

Waterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

Application of Multilateral Wells for Production and Enhanced Oil Recovery: Case Studies from Canada

Summary The use of multilateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multilateral wells focus on their production performance. Thus, what can be expected from such wells in terms of production is not clear, and this paper will attempt to address that gap. Taking advantage of public data, the production performance of multilateral wells in various Western Canadian fields has been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performance will be compared with nearby horizontal wells whenever possible. From the more classical dual and trilateral, to more complex architectures with seven or eight laterals, and the more exotic with laterals drilled from laterals, the paper will present the architecture and performance of these complex wells and of some fields that have been developed almost exclusively with multilateral wells. Interestingly, multilateral wells have not been used much for secondary or tertiary recovery, probably because of the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250-cp oil under polymer flood has achieved a cumulative production of more than 3 million bbl, which puts it among the top producers in Canada. Although multilateral wells have been in use for more than 25 years, very few papers have been devoted to the description of their production performance. This paper will bring some clarity to these aspects. It will also attempt to address when multilateral wells can be used and to compare their performance to that of horizontal wells in the same fields. It is hoped that this paper will encourage operators to reconsider the use of multilateral wells in their fields.

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

Challenges and Lesson Learnt of 1st IWAG Implementation in a Mature Oil Field, East Malaysia

Immiscible Water Alternating Gas (iWAG) scheme was adopted in Echo field, offshore Sarawak Malaysia, to increase recovery factor of the matured oil reservoir after more than two (2) decades of peripheral water injection. It was implemented through four (4) horizontal wells located at reservoir’s eastern and western flanks. Since the commencement of iWAG injection, multiple challenges occured interrupting the stable injection that halting the success of this integrated mega scale project. It started with prolonged iWAG performance test run due to surface constraint, measurement and well issues on executing switching test, followed with low injectivity during switching operation. Subsequently, injectivity issues occured in the gas phase after several injection cycles. In addition to that, injector wells facing high downtime due to surface facilities and well integrity issues, causing low injection rates and unavailability to meet cycle volume within the stipulated duration. Reactivation of iWAG benefiter wells also prove to be challenging due to wells have been idle for a long time and multiple interventions required to revive the well. Injection data for both gas and water phase were analysed to improve iWAG operating procedure and understand the wells performance. INJ-J2 was installed with temporary pressure gauge during the water to gas switching, while the other two (2) wells are equipped with Permanent Downhole Gauge (PDG) to monitor the well injectivity. Application of non-intrusive flowmeter was also proven useful in calibrating the Flow Transmitter (FT) for both water and gas injectors, ensuring the accuracy and precision in the water and gas injection measurement. Besides that, fluid temperature trending was referred to validate on the meter measurement. Low injection rate compared to original plan were reviewed with the Reservoir Management Plan (RMP). Several approaches are implemented in order to achieve the iWAG RMP target and idle well reactivation. Analysis of injection data showed that gas injectivity issue occurred after the water to gas switching cycle. Injectivity improves slightly after long duration of continuous gas injection and applying higher Tubing Head Pressure (THP), unfortunately some wells remain with low injectivity because of insufficient discharge pressure to push the water from the near-wellbore deep into the reservoir to improve injection. Low injection rate issue is mitigated by extending injection cycle duration in order to meet the RMP cycle volume. Besides that, wells are normally injected with higher injection rate to cater for the high downtime. Both gas and water injection are balanced to ensure that the wells reached their cycle volume at similar duration. With limited new field discovery by the Operator, tertiary recovery on the mature field is inevitable. However, there is less implementation of iWAG in offshore field. Through this paper, authors wish to provide insights and lesson learnt for others when planning for iWAG tertiary recovery, taking account of various challenges faced.

Application of Multi-Lateral Wells for Production and Enhanced Oil Recovery – Case Studies From Canada

The use of multi-lateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multi-lateral wells focus on their production performances, thus what could be expected from such wells in terms of production and recovery factor is not clear and this paper will attempt to address that gap. Taking advantage of public data, the production performances of various multi-lateral wells in Western Canada have been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performances will be compared to nearby horizontal and vertical wells whenever possible. From the more classical dual and tri-lateral to more complex architectures with 7 or 8 laterals, and the more exotic, with laterals drilled from laterals, the paper will present the architecture and performances of these complex wells and of some fields that have been developed almost exclusively with multi-lateral wells. Interestingly, multi-lateral wells have not been used much for secondary or tertiary recovery, probably due to the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250 cp oil under polymer flood has achieved a cumulative production of over 3MM bbl, which puts it among the top producers in Canada. Although multi-lateral wells have been in use for over 25 years, very few papers have been devoted to the description of their production performances. This paper will bring some clarity on these aspects. It is hoped that this paper will encourage operators to reconsider the use of multi-lateral wells in their fields.

New Formulation of Tertiary Amines for Thermally Stable and Cost-Effective Chemical Additive: Synthesis Procedure and Displacement Tests for High-Temperature Tertiary Recovery in Steam Applications

Summary A newly formulated chemical additive from a group of amines has been tested and applied to in-situheavy oil thermal recovery. Switchable-hydrophilicity chemical additives were successfully synthesized from N,N-dimethylcyclohexylamine in the form of homogeneous and hydrophilic solution. Fundamentally, tertiary amines comprise functional groups of hydrophilic and hydrophobic components. These unique features enable this chemical additive to wet both water and heavy oil, yielding potential interfacial tension (IFT) improvement. Furthermore, the reversible chemical reaction of this chemical additive yields both positive and negative ions. An ion pair formed due to the adsorption of cations—[C8H17NH+]—on the surface of heavy oil, whereas the anions—[HCO3−]—promoted solid-phase surface charge modification, therefore, resulting in the repulsive forces between heavy oil and the rock surface—substantially improving water-wetness and restoring an irreversible wettability alteration due to the phase change phenomenon during steam injection. In this research, two types of heavy oil acquired from a field in western Alberta encompassing the viscosity of 5,616 and 46,140 cp at 25°C was utilized in each experiment. All experiments were performed and measured at high-pressure, high-temperature (HPHT) steam conditions up to 200 psi and 200°C. We perceived that favorable IFT reduction was achieved, and irreversible wettability could be restored after combining switchable-hydrophilicity tertiary amines (SHTA) with steam as a result of the solid-phase surface charge modification to be more negatively charged. Phase distribution/residual oil in the porous media developed after steam injection was able to be favorably recovered, indicating that capillary forces could be reduced. Consequently, more than 80% of the residual oil could be recuperated post-SHTA injection, presenting favorable oil recovery performance. In addition to this promising evidence, SHTA could be potentially recovered by switching its reversible chemical reaction to be in hydrophobic form, hence, promoting this chemical additive to be both reusable and more economically effective. Comprehensive studies and analyses on interfacial properties, phase distribution in porous media, and recovery performance exhibit essential points of view in further evaluating the potential of SHTA for tertiary recovery improvement. Valuable substantiations and findings provided by our research present useful information and recommendations for fields with steam injection applications.

Thermodynamically consistent Darcy–Brinkman–Forchheimer framework in matrix acidization

Matrix acidization is an important technique used to enhance oil production at the tertiary recovery stage, but its numerical simulation has never been verified. From one of the earliest models, i.e., the two-scale model (Darcy framework), the Darcy–Brinkman–Forchheimer (DBF) framework is developed by adding the Brinkman term and Forchheimer term to the momentum conservation equation. However, in the momentum conservation equation of the DBF framework, porosity is placed outside of the time derivation term, which prevents a good description of the change in porosity. Thus, this work changes the expression so that the modified momentum conservation equation can satisfy Newton’s second law. This modified framework is called the improved DBF framework. Furthermore, based on the improved DBF framework, a thermal DBF framework is given by introducing an energy balance equation to the improved DBF framework. Both of these frameworks are verified by former works through numerical experiments and chemical experiments in labs. Parallelization to the complicated framework codes is also realized, and good scalability can be achieved.