Reservoirs which produce under active water drive offer a significant uncertainty towards implementation of Chemical EOR processes. This paper describes a successful pilot testing of ASP process in a clastic reservoir which is operating under strong aquifer drive. The field has ~ 30 years of production history. The objective of the pilot was to understand response of ASP process in a mature reservoir, which is operating under active edge water drive. The build-up permeability of the reservoir is 2-8 Darcy with viscosity~ 50 cP. Salient key observations like production performance, incremental oil gain, polymer breakthrough etc. are discussed in this paper after completion of the pilot.
On the basis of laboratory study and simulation, ASP pilot was implemented in the field in 2010.The pilot was designed with single inverted five spot pattern and one observation well. The pilot envisaged injection of 0.3 pore volume (PV) Alkali-Surfactant-Polymer (ASP) slug, 0.3 PV graded polymer buffer followed by 0.4PV chase water. The pilot was meticulously monitored for production performance and breakthrough of chemicals. All the pilot producers have more than 20 years of production history. Base oil rate and water cut were fixed before start of the pilot, on the basis of test data which was used to monitor pilot performance. Interwell Tracer Test (IWTT) was conducted before starting of ASP injection so as to understand sweep in the pilot area. In addition, quality of injection water and chemical concentration in ASP slug was checked regularly to ensure best quality.
Significant response of the pilot was observed within 15 months of the start of the pilot which was published in 2012. This paper aims to describe the learning and conclusion after successful completion of the pilot. ~40-50% jump in oil rate was observed during the ASP injection period which sustained for 12-18 months. However preferential breakthrough of ASP slug in one of the producer impacted the incremental oil gain. The preferential breakthrough of polymer was due to presence of high permeability streaks which was rectified by profile modification job. In addition, strong aquifer movement was experienced during ASP injection which leads to rise in water cut of a pilot well. However, the pilot well was restored through water shutoff jobs. After completion of ASP and mobility buffer, a cumulative incremental oil ~28000 m3 was obtained. Cumulative incremental oil gain is in line with simulation studies prediction. 12-14% decrease in water cut was observed which sustained for ~ 6-18 months. Regular monitoring of produced fluid indicated breakthrough of polymer and alkali in 2-3 producers. During the pilot, produced fluid handling issues like tough emulsion formation, lift malfunctioning etc. was not observed. These collective observation indicated success of the ASP pilot project.
There are very few case histories of successful ASP pilot implementation are available, in which the reservoirs has been operating under active aquifer drive. Learning of this ASP project can be taken forward for expansion of ASP flood and also designing of ASP pilot/commercial projects for analogous reservoirs.
The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
Simplified analytical methods are used in 1D geomechanics workflows to predict the rock's behavior during drilling, completion and production operations. These methods are simplistic in their approach and enable us in getting a time-efficient solution, however it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. Using 1D analytical methods, we are unable to predict full field behavior in response to drilling and production activities. For example, when developing a field wide drilling plan or preparing a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on stresses. It generates solutions which are more akin to reality.
In this paper, difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in this paper is quite complex - high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using well-centric approach and using a full field-wide 3D numerical solution and compared to understand the differences.
In this study, it was clearly observed that field-based approach provided us with more accurate estimation of overburden stresses, variation of pore pressure across the field, changes in stress magnitudes and captured its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the well-centric overburden estimates at the toe of deviated well at reservoir level is lower by 0.21gm/cc as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is due to effect of fault on stress magnitude and azimuth. Stress state of 4 faults were assessed and all are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, show them to be stable.
Moreover, the 3D geomechanical properties that are input into the numerical simulation also play an important role on the results. The algorithms and data used to populate the properties away from the well, need to be validated and calibrated with the well data, to predict reliable results. As the subsurface was quite complex, and well data was not sampled optimally, both horizontally and vertically, the selection and optimum usage of 3D trends also became crucial.
By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
High viscosity friction reducers (HVFRs) are an important component of slickwater hydraulic fracturing applications. To continue to treat multiple clusters effectively within longer laterals, even for stages near the toe area, a high molecular weight HVFR polymer, such as polyacrylamide, is commonly used to overcome pipe friction at 1 gal/Mgal or lower. To carry proppant into fractures, it is commonly assumed that the higher viscosity the HVFR yields, the better the proppant transport, necessitating higher HVFR concentrations than 1 gal/Mgal. However, a field study within the Anadarko Basin demonstrates that viscosity is not necessarily the best indicator of how efficiently HVFRs carry proppant. Instead, HVFR elasticity might play a more important role during proppant transport. Secondly, HVFRs concentration of 1 gal/Mgal or higher could potentially plug the proppant pack or form a filter cake on the rock surface, causing formation damage. Although previous laboratory methods to determine potential formation damage exist, results are difficult to correlate with field applications; hence, the conclusions remain elusive. A relatively new analysis procedure yielding improved assessments of residual HVFR concentrations for both flowback and produced waters, which aid understanding potential formation damage after hydraulic fracturing, is discussed.
Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Frøland, Anders (University of Bergen) | Viken, Anita (University of Bergen) | Rognmo, Arthur U. (University of Bergen) | Seland, John G. (University of Bergen) | Ersland, Geir (University of Bergen) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.
An accurate description of the microemulsion-phase behavior is critical for many industrial applications, including surfactant flooding in enhanced oil recovery (EOR). Recent phase-behavior models have assumed constant-shaped micelles, typically spherical, using netaverage curvature (NAC), which is not consistent with scattering and microscopy experiments that suggest changes in shapes of the continuous and discontinuous domains. On the basis of the strong evidence of varying micellar shape, principal micellar curves were used recently to model interfacial tensions (IFTs). Huh’s scaling equation (Huh 1979) also was coupled to this IFT model to generate phase-behavior estimates, but without accounting for the micellar shape.
In this paper, we present a novel microemulsion-phase-behavior equation of state (EoS) that accounts for changing micellar curvatures under the assumption of a general-prolate spheroidal geometry, instead of through Huh’s equation. This new EoS improves phase-behavior-modeling capabilities and eliminates the use of NAC in favor of a more-physical definition of characteristic length. Our new EoS can be used to fit and predict microemulsion-phase behavior irrespective of IFT-data availability. For the cases considered, the new EoS agrees well with experimental data for scans in both salinity and composition. The model also predicts phase-behavior data for a wide range of temperature and pressure, and it is validated against dynamic scattering experiments to show the physical significance of the approach.
Junwen, Wu (Sinopec Research Institute of Petroleum Exploration and Development) | Wenfeng, Jia (Sinopec Research Institute of Petroleum Engineering) | Rusheng, Zhang (Sinopec Research Institute of Petroleum Exploration and Development) | Xueqi, Cen (Sinopec Research Institute of Petroleum Exploration and Development) | Haibo, Wang (Sinopec Research Institute of Petroleum Exploration and Development) | Jun, Niu (Sinopec Research Institute of Petroleum Exploration and Development)
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (
The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery
The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance
The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.