bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Chemical Flood Efficiency by In Situ CO2 Generation
Authors: Shiau B. J. , Hsu Tzu-Ping , Roberts Bruce L. , Harwell Jeffrey H.
Published: July 2010

The purpose of this study is to investigate compounds that can generate carbon dioxide in situ, decrease the viscosity of oil and improve oil recovery. Several chemicals are studied for their potential to generate CO2 when exposed to elevated temperatures. Laboratory results show that ammonium carbamate can produce a significant amount of carbon dioxide when the temperature is elevated to 85° C. In contrast, negligible CO2 is detected while heating up the methyl carbamate to a similar temperature range. Ammonium carbamate is further studied in a one-dimensional sand pack column. Ammonium carbamate results in the production of CO2 in column studies at 80°C and 90° C and also results in a decrease in oil viscosity. The additional injection of a 0.5 PV of 3% ammonium carbamate solution with a polymer + surfactant chemical flood improved crude oil recovery by 9.7% OOIP compared to a polymer + surfactant chemical flood without carbamate. However, there is negligible oil recovery without the presence of surfactant for studies using light oils, decane and Arrow crude oil. The use of carbamate can have a positive impact on the mobility ratio for heavier oil, Elk Petroleum crude oil, by reducing crude oil viscosity. Instead of looking black, the crude oil exiting from the carbamate injected column appeared dark brown and less viscous. This suggests that a property of crude oil was changed by the CO2 generated in the column. Laboratory results also show that AMP (2-Amino-2-methyl-1-propanol) is also a promising candidate for generating carbon dioxide under high temperatures.
Potential for Polymer Flooding Reservoirs with Viscous Oils
Authors: Seright R. S.
Published: July 2010

This paper examines the potential of polymer flooding reservoirs with viscous oils. Higher oil prices, modest polymer prices, increased use of horizontal wells, and controlled injection above the formation parting pressure all help considerably to extend the applicability of polymer flooding in reservoirs with viscous oils. The high mobile oil saturation, degree of heterogeneity, and relatively free potential for crossflow in our target North Slope reservoirs also promote the potential for polymer flooding. For existing EOR polymers, viscosity increases roughly with the square of polymer concentration—a fact that aids the economics for polymer flooding of viscous oils. The key limitation for polymer flood application is not the chemical cost of viscous polymer solutions; instead reduced injectivity is the primary concern. For practical conditions during polymer floods, the vertical sweep efficiency using shear-thinning fluids is not expected to be dramatically different from that for Newtonian or shear-thickening fluids. The overall viscosity (resistance factor) of the polymer solution is of far greater relevance than the rheology.
Interfacially Active SWNT/Silica Nanohybrid Used In Enhanced Oil Recovery
Authors: Villamizar Luis , Lohateeraparp Prapas , Harwell Jeffrey , Resasco Daniel , Shiau Ben
Published: July 2010

Single-Walled-Carbon-Nanotube (SWNT)-Silica nanohybrid particles are a very promising material that could be used in a near future for enhanced oil recovery because of their interfacial activity. The mechanism used to recover additional oil in this case would be to deliver catalytically active nanohybrid particles to the O/W interface, where they would react with and modify the oil properties to mobilize the oil in the reservoir. To demonstrate the basic principle, aqueous nanohybrid particle dispersions were evaluated by looking at the effect of pH, salt, surfactant and polymer. The results showed that pH and salt did not have significant effect on the dispersion stability of nanohybrid particles. Although surfactant could improve the dispersion stability, it reduced the interfacial activity of the nanohybrid particles, causing them to stay in the aqueous phase. The best nanohybrid particle dispersion stability was found upon polymer addition, where the dispersions were stable for more than a week even at low polymer concentration (50 ppm).

After the best conditions for dispersions stability were determined, one-dimensional-sand-pack studies were performed to evaluate the flow of the nanohybrid particles through porous media. The results showed that the most of the nanohybrid particles could pass through a column packed with glass beads while a measurable fraction of the particles were retained in the column packed with crushed Berea. When the columns contained a residual saturation of decane, additional nanohybrid particles were retained at the oil/water interface in both media (glass bead and crushed Berea sand packs). The sand pack studies showed that not only can the nanohybrid particles flow through porous media, but also about half of the particles injected will go the O/W interface when the porous medium contains a residual saturation of hydrocarbon, where they could be used to support a catalytic conversion of components of the oil.
CO2-Soluble Surfactants for Improved Mobility Control
Authors: Xing Dazun , Wei Bing , Trickett Kieran , Mohamed Azmi , Eastoe Julian , Soong Yee , Enick Robert
Published: July 2010

Several commercially available, non-ionic surfactants have been identified that are capable of dissolving in CO2 in dilute concentration at typical MMP conditions and, upon mixing with brine, stabilizing CO2-in-water or CO2-in-brine emulsions or foams. These surfactants include water-soluble branched alkylphenol ethoxylates, linear alkylphenol ethoxylates, and branched alkyl ethoxylates. At 25 °C, the solubility of these surfactants in liquid CO2 at ~1300 psia (~9 MPa) is 0.02 – 0.10 wt%. When equal volumes of liquid CO2 and brine (5wt% NaCl) are mixed with these surfactants, an opaque, white emulsion forms that initiallyfills the entire high pressure view cell. This emulsion collapses, yielding a clear aqueous zone below the emulsion as the brine drains from the continuous films of surfactant-stabilized brine that separate the cells of dense CO2, and a clear CO2 zone above the emulsion as the droplets of CO2 coalesce. The stability of these emulsions, as measured by the rate of their collapse, is strongly influenced by the architecture of the surfactant. The most stable emulsions were achieved with water-soluble, branched alkylphenol ethoxylates, such as nonylphenol ethoxylates with 9-15 ethylene oxide repeat units, and linear alkylphenol ethoxylates, which yielded CO2-in-brine emulsions containing 9-23vol% brine that were stable for more than five hours.
Emulsion Flooding of Heavy Oil
Authors: Kumar R. , Dao E. , Mohanty K. K.
Published: July 2010

The goal of this work is to develop alkaline-surfactant methods to improve recovery from a heavy oil reservoir in the north slope of Alaska. Phase behavior experiments were conducted to determine conditions under which oil-in-water emulsions form. The viscosity (and its shear dependence) was measured for some of these emulsions. Reservoir sand was assembled in sand packs. Water flood and alkaline-surfactant floods were conducted at several salinities. Several relatively hydrophilic surfactants were identified which formed oil-in-water emulsions with the reservoir oil at a low concentration in the presence of sodium carbonate. Emulsions formed at low salinity and high oil-water-ratio. Viscosity of these emulsions was relatively low compared to the oil viscosity. Waterflood recovery was of the order of 20-30% PV and it decreased as the injection rate increased. The alkaline-surfactant flood following the waterflood gave an incremental oil recovery of 20-40 % PV. Alkaline-surfactant floods look promising, but the mechanisms of this flood need to be understood to upscale this process to the field.
Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility Control Applications
Authors: Espinosa David , Caldelas Federico , Johnston Keith , Bryant Steven L. , Huh Chun
Published: July 2010

Surfactant-stabilized CO2 foams have been used for mobility control for CO2 flooding; however, stabilization of foams with nanoparticles has some important advantages for EOR applications. Bringing the nanoparticles to the bubble interface requires a large adsorption energy, making the resulting foam very stable. Nanoparticles being solid, the nanoparticle-stabilized foams have potential to withstand the high-temperature reservoir conditions for extended periods. With their very small size, nanoparticles (and foam bubbles stabilized by them) can be transported without straining in pore throats in the reservoir rock.

Very stable supercritical CO2-in-water foams were generated with 5-nm silica nanoparticles whose surface was treated with short-chain polyethylene-glycol. The foams were generated by co-injecting CO2 and an aqueous dispersion of the nanoparticles through a glass-beads pack, at mixture flow rates that correspond to shear rates of ~1300 s-1. The domain of foam stability and the normalized mixture viscosity have been measured for a range of values of nanoparticle concentration, water salinity, ratio of CO2/water flow rates, the overall flow rate and temperature. With deionized water, stable foams formed at nanoparticle concentrations as low as 0.05 wt%. Larger particle concentrations were required to maintain foam stability at larger salinities, e.g., 0.5 wt% particle concentration for 4% NaCl brine. Foam stability was independent of CO2/water volume ratio for ratios between two and eleven, but the normalized mixture viscosity increased with the increase in ratio. When foam was generated, it had two to eighteen times more resistance to flow than the same fluids without nanoparticles. Foams were generated at temperatures up to 95 °C. Foam generation by co-injection of the fluids appears to require a threshold shear rate.
A Designer Water Process for Offshore Low Salinity and Polymer Flooding Applications
Authors: Ayirala Subhash , Uehara-Nagamine Ernesto , Matzakos Andreas , Chin Robert , Doe Peter , van Den Hoek Paul
Published: July 2010

Low salinity water flooding is getting much wider attention in the oil industry since it is highly cost-competitive compared to other conventional EOR methods. Water desalination and hardness removal are the keys to its success for effective oil recovery. However, conventional seawater desalination methods provide almost fresh waters that could be incompatible with resident reservoir clays and hence may not be suitable for direct injection into the reservoir. In this paper, we describe a novel "designer water" desalination scheme that is capable of providing the desired injection water composition to suit the specific formation. Thus, this process could potentially avoid clay-swelling, and at the same time mitigating other critical issues such as reservoir souring and unfavourable wettability modification to more oil-wet state. Selected examples are given to conceptually demonstrate how various water streams generated in the designer water process would help to move the injection water quality point away from the clay flocculation region for different reservoir clay types.

Polymer flooding is another promising avenue for low salinity water applications. The use of low salinity water in polymer flooding processes considerably reduces the amount of dosing chemicals required to achieve a target polymer solution viscosity. This favourably impacts chemical procurement, transportation, storage, and handling (mixing and hydration) requirements and operating costs in offshore environments. The effect of injection water salinity on polymer concentration requirements is shown for different polymer solution viscosities. These data indicate about 5-10 times lower consumption of polymer in low salinity water when compared to seawater. As a result, a high-level facility engineering study was performed to assess the cost savings associated with low salinity water in offshore polymer flooding. The study results show that polymer flooding with low salinity water is economically more beneficial compared to seawater polymer flooding. It could be possible to pay out the incremental desalination costs within a 4-year project time frame due to the large savings associated with chemical costs and polymer facilities costs in low salinity polymer flooding. When the reservoir fits the criteria for low salinity flooding, then the additive effect of lower waterflood remaining oil saturation compounds with the benefit of polymer flood improved oil recovery due to better reservoir sweep. This means that low salinity water flooding can synergize well with polymer flooding to drive unit technical cost down and oil recoveries up.
Propagation of Colloidal Dispersion Gels (CDG) in Laboratory Corefloods
Authors: Spildo K. , Skauge A. , Skauge T.
Published: July 2010

Laboratory core floods have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). CDG consist of roughly spherical particles with sizes in the nanometre range (50-150 nm), formed by a crosslinking reaction between aluminium and partially hydrolysed polyacrylamide (HPAM). Investigations have shown that the physio-chemical properties of CDG solutions are similar to aqueous solutions of colloids. Such solutions may contribute to EOR by giving both microscopic diversion of flow and macroscopic sweep improvement.

Questions have been raised as to whether CDGs can propagate a substantial distance into porous rock and thus contribute to oil mobilization. To our knowledge, this matter has previously not been subject to experimental verification. The present study reports several experiments dedicated to investigate this matter.

CDG retention in porous media can be due to adsorption, mechanical entrapemnt and/or a log-jamming mechanism. More extended polymer molecules can also be retained by mechanical trapping in the presence of sufficiently small pore throats. We have studied the retention of polymer and aluminium in Berea cores, both separately and as part of a CDG formulation. The results show no chromatographic separation between aluminium and polymer in the CDG injection experiments. The core floods have also shown a constant equilibrium ratio between aluminium and polymer being produced. Earlier laboratory results have also shown no change in particle size distributions of the CDG formulation in the effluent after an oil mobilization experiment.
Nano-Sized Particles for EOR
Authors: Skauge Tormod , Hetland Sverre , Spildo Kristine , Skauge Arne
Published: July 2010

During the last decades colloidal dispersion gels (CDG) have been applied as an EOR method, providing sweep improvement in reservoirs with unfavourable mobility ratio. Our core flood results also indicate an improved microscopic sweep or microscopic diversion by CDG. This paper investigates the oil mobilization properties of nano-sized silica particles in comparison to nano-sized CDG particles and discusses the underlying mechanisms of microscopic flow diversion.

Improved microscopic displacement efficiency has traditionally been coupled to changes in capillary number. However, this approach is insufficient to describe processes like low salinity injection, colloid dispersion gels, and microbial enhanced oil recovery.

This paper presents a new concept of EOR by improved microscopic displacement defined as microscopic diversion. This method involves pore blocking and diversion of injection fluids. Multi-phase flow experiments using nano-sized silica particles attempts to investigate the effect (inelastic) nano-sized fines migration can have on oil mobilization by microscopic diversion.

The oil mobilization properties were investigated by core floods using well-defined nano-sized silica particles in comparison with injection of CDG, polymer or silica particles dispersed in a polymer solution. Core floods were performed on water-wet Berea sandstone cores with permeabilities of approx. 500 mD. The comparison of inelastic silica particles, polymer solutions and nano-sized CDG particles allowed an evaluation of the importance of viscoelastic properties for microscopic diversion.
Water Shut-off Polymer Systems: Design and Efficiency Evaluation based on Experimental Studies
Authors: Vega I. , Morris W. , Robles J. , Peacock H. , Marín A.
Published: July 2010

Water production control is a key issue in most mature reservoirs worldwide. Many techniques have been developed to achieve this purpose. Water Shut-off (WSO) treatments using crosslinked gels have proven to be an effective alternative. When appropriately designed and applied, these systems generate flow restrictions in high permeable or fractured formations that bypass water from highly saturated zones (injection water or natural brines). WSO treatments efficiency depends on several aspects as reservoir fluids flow patterns, rock petrophysics, formation heterogeneity, and WSO gel characteristics. This last aspect is adjusted to optimize the treatment based on experimental tests performed in the laboratory.

This paper presents an experimental methodology to evaluate and adjust WSO polymer systems according to operational and treatment performance requirements. These studies go from qualitative gel consistency and fluid compatibility bottle tests, to rheological characterizations to determine viscosity variations and gelation time (outside porous media tests), as well as flow tests performed on formation and Berea core plugs at reservoir conditions (inside porous media tests).

These properties are highly important to avoid early gelations and, at the same time, assure the appropriate WSO placement in the reservoir. Viscoelastic properties such as G* (complex modulus), G′ (storage modulus) and G″ (loss modulus) define the gel strength and provide structural information such as crosslinking density. These parameters are essential to design the gel formulations (polymer and crosslinker type and concentration) depending on the operational and reservoir requirements.

Finally, the flow tests performed on core plugs show the changes in water and oil permeability after injecting the treatment. This information is used to calculate the residual resistance factors to water (RRFw), oil (RRFo) and the gel resistance index (GRI). These parameters define the treatment blockage degree and allow estimate probable well production response as well as the best production regimes to extend the treatment life time. This methodology was applied on a new WSO gel system, developed for a wide range of applications. The effect of polymer concentration, temperature, salinity and flow rate are examined in detail.

Experimental tests are many times underestimated when planning a WSO job; however these tests will always provide valuable information that will increase the chances of successful water shut-off treatments. The connection between laboratory and field parameters and its influence in the oil and water productivity were analyzed.
New Gel Aggregates for Water Shut-off Treatments
Authors: Lei Guanglun , Li Lingling , Nasr-El-Din Hisham A.
Published: July 2010

A common problem for oil production is the excessive water production, which can lead to rapid productivity decline, and enhancement in operating costs. The result is often a premature shut-in of wells because production has become uneconomical. In water injecting wells, the water injection profiles are uneven and large amounts of oil have been left behind the waterfronts.

Many chemical systems have been used to control water and improve recovery from reservoirs with high water-cut. Non-polymer or inorganic gels have low viscosity and can be pumped using typical field mixing and injection equipment. Polymer or cross-linked gel, especially polyacrylamide, based techniques are largely used because of their relatively low cost and their supposed selectivity.

In this paper, microspheres (5-30 microns) were synthesized using acrylamide monomers cross-linked with an organic cross-linker. They can be suspended in water and be pumped in sandstone formations. They can plug some of the pore throats, thus force water to change its direction and increase the sweep efficiency. A HPHT rheometer was used to measure G' (elastic modulus) and G" (viscous modulus) of these aggregates.

Experimental results indicate that these microspheres are stable in solution with 20,000 ppm NaCl, at 175°F. They can expand up to 5 times of their original size in water and show good elasticity. The results of sand pack tests show that the microspheres can flow into cores with more than 500 md and can increase the resistance factor by 8~25 times and the residual resistance factor by 9 times. Addition of microspheres to polymer solutions further increased the resistance factor beyond that obtained with polymer solution. Field data using microspheres showed improvement the in the injection water profile.
Two-Phase and Three-Phase Saturation Routes and Relative Permeability During Fast Drainage
Authors: Dehghanpour H. , DiCarlo D. A. , Aminzadeh B. , Mirzaei M.
Published: July 2010

We conduct two- and three-phase drainage experiments in a 0.8 meter water wet sand column with varying initial conditions. We measure saturations versus space and time using a dual energy CT-scanner technique. A non-linear interpolation technique is used to synchronize measured CT profiles. The relative permeabilities are determined using the fluxes obtained from the measured saturation profiles and assuming flow under unit gravitational gradient.

At times greater than 15 minutes, the gradient of oil and water saturation data is relatively small far from the air front, allowing accurate determination of relative permeabilities. We observe a pronounced difference in the drainage behavior of the systems with and without initial trapped air. For early times and high saturations (S>0.3), we obtain relative permeabilities and they follow the previously measured trend at low saturations. We compare two- and three-phase relative permeabilities of oil and water. We explain the optimum initial condition for relative permeability measurement during gravity drainage, and we discuss the situations where this method fails to determine representative relative permeability data.
Application of the Multiwell Productivity Index-Based Method to Evaluate Interwell Connectivity
Authors: Kaviani D. , Valkó P. P. , Jensen J. L.
Published: July 2010

Numerous studies have concluded that connectivity is one of the most important factors controlling success of improved oil recovery processes. Interwell connectivity evaluation can help identify flow barriers and conduits and provide tools for reservoir management and production optimization. The multiwell productivity index (MPI)-based method provides the connectivity indices between well pairs based on injection/production data. By decoupling the effects of well locations, skin factors, injection rates, and the producers’ bottomhole pressures from the calculated connectivity, the heterogeneity matrix obtained by this method solely represents the heterogeneity and possible anisotropy of the formation. Previously, the MPI method was developed for bounded reservoirs with limited numbers of wells. In this paper, we extend the MPI method to deal with cases of large numbers of wells and open reservoirs.

To handle open reservoirs, we applied some modifications to the MPI method by adding a virtual well to the system and by modifying the pore volume. We applied the modifications in two nonvolumetric systems where there was either a leaking zone or an isolated zone, and found the approaches using the virtual well could predict the reservoir performance accurately. In cases with large numbers of wells, the required computational time to calculate the heterogeneity matrix may make the problem intractable. Therefore, we applied a model reduction strategy based on the location of the wells, called windowing. This technique ignores the parameters that have smaller effects on reservoir performance. We applied windowing to two cases with large numbers of wells (16 and 41 wells). We observed that, by selecting the proper window size, we can predict the reservoir performance accurately (R2 values greater than 99%) and decrease the CPU time up to a factor of 20 for the studied cases.

The approaches described enabled us to provide realistic interpretations of interwell connectivity for complex cases where the simple MPI method would be difficult to apply. Integration of these approaches with the MPI method can quickly and efficiently model field data to optimize well patterns and flood parameters.
Simultaneous Water-Gas-Injection Performance Under Loss of Miscibility
Authors: Ghanbarnezhad Rouzbeh , Lake Larry W.
Published: July 2010

This paper concerns the limits of the Walsh and Lake (WL) method for predicting solvent-flood performance when miscibility is not achieved. Despite extensive research on applications of fractional flow theory, prediction of flow under loss of miscibility has not been investigated thoroughly.

We introduce the idea of an analogous first-contact miscible (FCM) flood to the WL method. To compare the WL solution of degraded miscible simultaneous water and gas (SWAG) displacements, we use numerical simulations. In the simulations, the loss of miscibility is attributed to either dispersion or insufficient pressure (degradation).

The results of one-dimensional (1D) SWAG injection suggest that results of the WL method and the simulations are in agreement when the input dispersion is limited. For the two-dimensional (2D) displacements, the WL predicted optimal water- alternating-gas (WAG) ratio is accurate in two sets of simulation cases: (1) fairly homogeneous permeable media with limited cross flow (2) heterogeneous permeable media with lateral correlation length of the same size or larger than the interwell spacing. The accuracy of the WL method improves in the latter cases as the cross flow decreases. Also, we observe a linear growth of the mixing zone with time in cases where the WL solution and the numerical results are consistent. Further investigation illustrates an inverse relation between the level of mixing, resulting from the input dispersion and heterogeneity, and the accuracy of the WL approach. Through this work, the effect of dispersion and miscibility degradation on the miscible residual oil saturation, Sorm, is determined.
Results of a Three-Well Waterflood Sweep Improvement Trial in the Prudhoe Bay Field Using a Thermally Activated Particle System
Authors: Husband Michael , Ohms Danielle , Frampton Harry , Carhart Steve , Carlson Brian , Morgan Jim C. , Chang K. T.
Published: July 2010

Maintaining proper waterflood conformance is a critical component of waterflood management. Most methods used to control waterflood conformance have proven to be only marginally effective. A unique technique has been developed for creating a durable reservoir flow restriction that diverts injected water into unswept reservoir sections. Placement of the restriction is based in the location of the thermal front between the injector and producers. The performance of this thermally activated particulate system for waterflood conformance control has been evaluated in a three injection well trial in the Prudhoe Bay oilfield, Alaska. The aim of the trial was to determine the incremental oil produced and improvement of sweep efficiencies for three interior water injection patterns in the east waterflood area of Greater Prudhoe Bay Unit.
Wettability Challenges in Carbonate Reservoirs
Authors: Alotaibi M. B. , Nasralla R. A. , Nasr-El-Din H. A.
Published: July 2010

Injection of water for pressure maintenance and waterflooding applications is becoming an increasingly important issue. Historically, the total suspended solids of the water were given more consideration rather than the total dissolved solids. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Displacement of the oil is highly affected by many interacting variables. Wettability has been recognized as one of the controlling parameters of the remaining oil-in-place. Brine salinity, oil chemistry, and rock lithology are believed to play a significant role on altering rock wettability. Recent studies highlted that low salinity water can increase oil recovery in carbonate reservoirs.

This paper highlights extensive wettability studies to determine the optimum brine salinity, which results in higher oil recovery. Contact angle and Amott imbibition methods are considered as the most common methods to measure the preferential affinity of reservoir rocks. Crude oil, formation core samples (dolomite, and calcite), and synthetic brines from Middle East (formation, aquifer, and seawater) are used to evaluate wettability quantitatively, and qualitatively. All experiments were conducted at high pressure (up to 2,000 psia), and elevated temperature (up to 270°F).

Contact angle decreased with pressure, and temperature upto 194°F. The optimum salinity is found that can enhance the rock wettability toward water-wet. Currently, there is confusion concerning the optimum brine salinity for injection wells. The results of this study give a new insight on the optimum salinity and provide better understanding of some wettability challenges in carbonate reservoirs.
Investigation of Pore-Scale Mixed Wettability
Authors: Kumar Munish , Fogden Andrew , Senden Tim , Knackstedt Mark
Published: July 2010

The efficiency of secondary and tertiary recovery processes can be improved by properly taking into account the reservoir's true wettability state. Most reservoirs are assumed to be mixed-wet, based on core-scale indexes such as Amott-Harvey and USBM. Oil-brine-mineral contact angle measurements on smooth substrates offer some molecular-scale input and estimates for network modelling. However, direct experimental techniques to characterize wettability and validate the mixed-wet model at the pore scale in real or model rocks remain elusive. One promising avenue is the use of micro-tomography (μ-CT) to map the pore-scale distribution of multiple phases in miniplugs. A second, complementary approach involves the study of model rocks based on bead packs to probe the surface chemistry of the minerals exposed to crude oil and brine in pore confinement. Integrating the two approaches described in the current study provides a promising means to explain the observed multiphase fluid occupancy in pores by combining the detailed knowledge of the 3D pore structure and information on the surface chemistry of its walls.
A Comprehensive EOR Study Using Low Salinity Water in Sandstone Reservoirs
Authors: Alotaibi M. B. , Azmy R. M. , Nasr-El-Din H. A.
Published: July 2010

It has been reported that the ionic strength of injection water can have a major impact on the recovery of hydrocarbons during waterfloods, with increased recovery resulting from the use of low salinity brines. Understanding how the water and oil chemistry affects the final recovery from a physicochemical point of view is necessary in order to optimize low salinity water flooding process. It is clear from the literature over the last two decades that wettability is considered a key factor in achieving the low salinity effect. Optimum ionic strength and conditions for low salinity flood with respect to wettability is still uncertain.

In this study, we integrate new coreflood apparatus using core samples, up to 20 inch length, to mimic and understand crude oil/water/rock interactions. The coreflood experiments are conducted under both secondary and tertiary recovery modes. We applied contact angle method to study rocks wettability. Reservoir rocks and stock-tank crude oil sample (west Texas) are utilized in all experiments. Synthetic brines varying in salinity (up to 174kppm) are tested under elevated temperature and pressure conditions. As ion exchange plays a crucial role in changing wettability, chemical analyses are performed on the effluent samples. Moreover, Zeta potential is determined for sandstone rocks and selected clays as a function of ionic strength.

Residual oil saturation is determined with all variation in wettability, brine salinity, and temperature conditions. Some core flood tests give an incremental increase in produced oil as decreasing the injection brines ionic strength. Experimental results indicate that adjusting brine salinity may enhance oil recovery under certain conditions. This paper gives a new insight into optimum salinity and provides better understanding of interaction between injected brine, the oil, and the rock at downhole conditions.
Field Applications of Behind-Pipe Saturation Evaluation in a Miscible CO2 Flood
Authors: Hughes R. G. , Amadi S. U. , D'souza D. F.
Published: July 2010

To evaluate the amount of bypassed oil in a CO2 flood, it is necessary to obtain some estimate of the remaining oil saturation. Near wellbore oil saturation determination requires a tool or sequence of tools that is able to distinguish oil from other phases that may be present in situ especially when those phases are miscible with the oil. Cased hole logging in waterfloods, steam floods and CO2 sequestration cases has been presented and the techniques used are in the process of becoming reasonably reliable evaluation tools. Very little work has been presented on the case where an existing CO2 flood needs to be evaluated, but has no baseline cased hole logs to tie to.

This paper presents the results of field tests where carbon-oxygen and pulsed neutron logs were used in combination to evaluate in situ saturations in an area where oil, water and CO2 are present but where no previous (baseline) cased hole logs had been run. One of the wells had a nearby core characterization and modern open-hole logs to tie the cased hole logs to while another was in the same formation, but only had 1960's vintage open-hole logs. Techniques described in a previous publication were used to perform the evaluation.

The theoretical result previously presented worked fairly closely to what was described. However, there are a number of variable parameters required that need to be evaluated and reasonable estimates (or methods to obtain reasonable estimates) of those values are not well documented. This paper will also document the methodologies that seemed to work to successfully estimate these parameters.
The Role of Co-Solvents and Co-Surfactants in Making Chemical Floods Robust
Authors: Sahni Vinay , Dean Robert M. , Britton Chris , Kim Do Hoon , Weerasooriya Upali , Pope Gary A.
Published: July 2010

The ability to select low-cost, high-performance surfactants for a wide range of crude oils and reservoir conditions has improved dramatically. There are thousands of possible combinations of chemicals and components (including differing salinities, hardness, and oil concentrations) that could be tested on each crude oil. Each chemical combination requires many observations at reservoir temperature for proper evaluation. Therefore it would take too long, be too expensive, and in many cases not even be feasible to test all combinations. In practice we use our scientific understanding of surfactant/co-surfactant/co-solvent characteristics to match a chemical formulation to the properties of a crude oil and formation brine salinity at reservoir temperature. Typically the surfactant is mixed with other chemicals such as polymer in brine and injected at optimum salinity (the ASP slug). It is important that the ASP slug be a clear, stable solution since precipitation or phase separation will interfere with surfactant and polymer transport deep into the reservoir. Co-solvents and/or co-surfactants are often needed to make the primary surfactant sufficiently soluble. Core floods are presented that show the oil recovery is significantly increased by simply adding a small concentration of co-surfactant to make the ASP slug clear. In such cases, the use co-solvent/ co-surfactant is economically beneficial in terms of higher oil recovery because of the improved surfactant performance, lower surfactant retention and improved effectiveness of the polymer for mobility control.
Alkaline - Surfactant - Polymer Flood (ASP): Single Well Chemical Tracer Tests - Design, Implementation and Performance
Authors: Oyemade S. N. , Al Harthy S. A. , Jaspers H. F. , Van Wunnik J , de Kruijf A. , Stoll M.
Published: July 2010

Studies in a number of mature fields in Oman have shown that alkaline surfactant polymer (ASP) flooding can potentially yield significant incremental recoveries with respect to water flooding. The technique however, is still immature especially in PDO as reflected in the number of key risks that have been identified; (i) poor injectivity of the ASP slug, (ii) effectiveness of reservoir sweep, (iii) formation of scale in the wells and facilities and (iv) persistent emulsions in the produced fluids. Analysis of these risks has highlighted the need for piloting before full field implementation.

Two stages of piloting have been considered, Single Well Chemical Tracer (SWCT) test and Continuous Injection Pilot (CIP). This paper covers the SWCT trials with focus on design and implementation challenges and finally discusses performance and results.

A total of five wells were selected for the trial in three different fields across Oman to capture different reservoir settings. The ASP SWCT tests aim to confirm the suitability of the ASP process, the potential recovery factor increase and mitigate some key risks, mainly injectivity and sweep. The trials are designed to evaluate the remaining oil saturation before and after injection of ASP cocktails to determine incremental oil recovery.

Various challenges were faced in planning the project. Completion challenges due to age of existing wells / casing, well shape, type of artificial lift, need to produce / inject water and ASP cocktail from same wells. Water source / tie-in for preliminary flooding also varied in each field. Handling of produced fluids during tests required special attention to avoid destabilizing the production station. Treatment sequence, equipment layout and logistic requirements were different for each field. Procedures were developed for each field incorporating chemical preparation and mixing. Overall, Project Management and good interface were critical to successful implementation of the tests, the first in PDO.
Fracturing Design Aimed at Enhancing Fracture Complexity
Authors: Soliman M. Y. , East Loyd , Augustine Jody
Published: July 2010

The potential for shale formations as a source of gas production has been recognized. However, shale permeability in a nano-Darcy scale represents a significant technological challenge to recover trapped hydrocarbon effectively. The fracturing of wells has been widely used to enhance the economic aspects of the reservoir. Connecting the created hydraulic fractures to the natural fractures or induced-stress fractures would further improve the productivity of the wells. Fracturing heterogeneous (naturally fractured) formation involves unique aspects in the fracturing processes, rock mechanics, and fluid-flow aspects.

In some cases, the natural fractures might not be sufficiently conductive or could be held closed during fracturing operations as a result of the existing in-situ stresses. In this paper, hydraulic fracturing-design techniques to neutralize the stress anisotropy in the formation to allow the opening of the natural fractures during the hydraulic-fracture propagation are presented. Overcoming anisotropy effects would allow the operator to inject moderate amounts of proppant into the natural fractures and maximize the contact area within the reservoir.

Geomechanics development behind these techniques is presented in this paper. The presented technology would allow operators to optimize placement of fractures across the horizontal well based on the geomechanics properties of the formation. The fluid-flow aspects of these enhanced completion processes are also discussed.
Interfacial Stability and Displacement Efficiency in Thermal Solvent Processes
Authors: Sharma Jyotsna , Gates Ian D.
Published: July 2010

Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) and Solvent-Assisted Cyclic Steam Stimulation (SA-CSS) are in situ steam-solvent recovery process to produce heavy oil and bitumen reservoirs. In ES-SAGD and SA-CSS, steam and solvent are injected into the depletion chamber within the reservoir. At the chamber edge, the steam releases its latent heat heating the oil there and solvent mixes with mobilized bitumen which then flows under gravity to the lower horizontal producer. There are many factors that influence the efficiency and rate at which oil is mobilized. One of them is the stability of the steam-oil interface which is controlled by the concentration and temperature dependencies of viscosity and density and the relative magnitudes of viscous, gravity (buoyancy), and capillary forces. In this research, the stability of the chamber interface between the vapour chamber and the bitumen at the edge of the chamber is examined. We present theoretical evidence for occurrence of such instability and conditions at which the interface is unstable. The results demonstrate that steam-solvent injection enhances the instability of the interface thus promoting greater mixing at the edge of the chamber. Consequently, the oil rate of a steam-solvent process is higher than that of a steam-only one. Therefore, there are three fundamental contributions to enhanced production by solvent-steam processes: first, the oil phase viscosity is lowered, second, the oil saturation is enhanced at the edge of the chamber, and third, the vapour-oil interface becomes more unstable which promotes more mixing at the chamber edge. The stability of the interface is also controlled by the balance between the solvent's solubility in the oil phase and the ability of the solvent to reduce the viscosity of the oil phase. The results of the stability analysis confirm the findings of laboratory experiments and field tests which demonstrate that processes that use solvent+steam yield higher production rates than that of steam alone.
Valhall – Pushing the Limits for Openhole Zonal Isolation — Qualification and Field Trial of 10,000-psi Oil-Swelling Packers
Authors: Nijhof Jeroen , Koløy Tom Rune , Andersen Kristian
Published: July 2010

The paper outlines the full-scale qualification testing of high differential pressure (ΔP) swellable element packers (SEPs) for fracture stimulation application in prop fracture stimulation in production wells on the Valhall Field, which is operated by BP Norge AS.

The SEPs use solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe, which forms part of the reservoir liner. This eliminates the need to spot dedicated swelling fluid.

Also discussed is the system used to perform the fracture stimulation in the field. The results of the successful qualification full scale testing up to 10k psi across two 5-meter packers are described. Details are also given for the Valhall Field operation with the deployment and swelling of 20 SEPs, followed by the hydraulic fracturing operation.

Reservoir management for the Valhall redevelopment program relies on multi-zone water injection and proactive management of unwanted water production. Produced water isolation is achieved with an arrangement of heavy-duty sliding sleeve circulating devices. A method of annular zonal isolation to prevent flow behind the reservoir liner is essential to success.

The oil-swelling SEPs offer a viable alternative and several improvements over the currently used cement barriers. These advantages are described in the paper. At the heart of these is the key requirement that any annular barrier must withstand very high ΔP (10k psi) during stimulation of the individual producing zones.

Several unsuccessful attempts had been performed to qualify a SEP to 10k psi for Valhall; therefore, it was decided to try a new design featuring an innovative mechanical end-ring system. This represents a step change in the design methodology of SEPs. It enables reduction of element length and packer OD while retaining high differential pressure (DP) ratings and/or increase the DP rating of long SEPs. The features and benefits of the new SEP design are presented.
Evaluating the Effects of Well-Type Selection and Hydraulic-Fracture Design on Recovery for Various Reservoir Permeability using a Numeric Reservoir Simulator
Authors: Shelley Robert F. , Soliman M. Y. , Vennes Mike
Published: July 2010

The industry is faced with the task of producing hydrocarbon from increasingly tighter reservoir rock, including low-permeability sand and shale. As a consequence, the selection of an appropriate well type and fracture-stimulation design is becoming more critical to project success. The purpose of this paper is to provide some clarity by providing a general understanding about the effects of well-type selection and hydraulic-fracture design on hydrocarbon recovery for various reservoir-permeability scenarios. Well types modeled include vertical, stimulated vertical, horizontal, axial-stimulated horizontal, and transverse stimulated horizontal with variations in compartment length and effective fracture length. This information has proven useful in the evaluation and planning of moderate to low to ultralow-permeability well projects.

The summaries presented in this paper are a compilation of the results from numerous simulator runs for black oil, gas condensate, and gas cases. These simulator runs included sensitivities on well type and permeability to compare recovery and production. Important conclusions pertaining to the recovery of hydrocarbon from low-permeability reservoirs and shale are made. In addition to validating the obvious conclusion about the increasing difficulty in recovering hydrocarbons from lower-permeability rock, a primary conclusion is that, as reservoir permeability decreases, proper well-type selection and correct hydraulic-fracture-stimulation design becomes much more crucial. The conclusions also show that, for a given permeability, obtaining significant recovery of oil can be a much more difficult problem than with dry gas.
Enhanced Gas Recovery, Challenges Shown at the Example of three Gas Fields
Authors: Clemens Torsten , Secklehner Severin , Mantatzis Konstantinos , Jacobs Bas
Published: July 2010

CO2-EOR has been used successfully to recover incremental oil after water flooding. In the USA, more than 260,000 bbl/d are produced by using this EOR method. CO2 Enhanced Gas Recovery (CO2-EGR) has also been proposed, however, only small scale projects have been performed until know.

In this paper, the challenges of CO2-EGR are addressed at the example of three fields.

The Hoeflein Field (Austria) contains gas condensate with a maximum liquid drop out of 4 %. The simulation results show that CO2 injection can recover incremental condensate. However, owing to the shape of the reservoir, CO2 will break through early. Hence, gas recovery will be reduced compared with conventional gas production.

The second field which was investigated is located in Pakistan. This field is an elongated field. The production wells are distributed over the full length of the field. CO2 injection can increase recovery (0.2 % maximum) only, if the surface facilities are able to handle high CO2 contents in the produced gas (more than 50 %).

The Schoenkirchen Uebertief Field (Austria) is a deep (5700 mSS), elongated structure. The production wells are located at one end of the structure. To recover incremental gas, good well placement and gas injection later in the lifetime of the field is required, about 1.5 % additional gas compared with depletion drive can be expected.

The example cases of CO2-EGR show that even for almost ideal reservoir structures (elongated with wells at one end and injection at the other end), limited potential for CO2-EGR exists. To increase gas production compared with depletion, a good well placement and knowledge of the structure accordingly is required, the production facilities have to be able to handle high CO2 contents and CO2 injection should commence later in the life-time of the field to avoid trapping of hydrocarbon gas in unswept areas at high pressures.