bluuebunny/crossref_metadata_2025 huggingface dataset:
Surfactant Effect On Foam: From Core Flood Experiments To Implicit-Texture Foam-Model Parameters
Authors: Jones S. A. , Laskaris G. , Vincent-Bonnieu S. , Farajzadeh R. , Rossen W. R.
Published: March 2016

Aqueous foams play an important role in many industrial processes, from ore separation by froth flotation to enhanced oil recovery (EOR), where the foam is used as a means of increasing sweep efficiency through oil-bearing rock. The complex, structure-dependent, flow behavior of the foam gives improved penetration of lower-permeability regions. Foam is stabilized by surfactant molecules, and the foam strength is influenced by the surfactant concentration in the water phase. It is therefore of great importance to understand the effect of surfactant concentration on foam processes.

Implicit Texture (IT) foam models eg STARS account for the surfactant effect with functions that depend on surfactant concentration in the water and a few other parameters. However, there is no evidence that these functions are able to capture adequately the effect of surfactant concentration effect. We present a comparative study of foam core-flood experiments with various surfactant concentrations. Core-flood tests were conducted in rock cores with a diameter of 1 cm and length of 17cm, significantly smaller than typical cores. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micellar concentration (CMC) and above. Bulk foam stability and surface tension were measured for all concentrations, in order to define the CMC and to compare with coreflood results. The experimental results have been matched with the STARS IT foam model and the dependency of model parameters on the surfactant concentration is discussed.

This work found that the IT model is not able to predict the decrease of the foam strength with decreasing surfactant concentration. Instead, the study shows that the effect of surfactant concentration can be correlated with the dry-out function of the IT model, and specifically to the limiting capillary pressure
Oil Recovery from Outcrop Cores with Polymeric Nano-Spheres
Authors: Lenchenkov Nikita S. , Slob Michiel , van Dalen Ernst , Glasbergen Gerard , van Kruijsdijk Cor
Published: March 2016

In order to improve oil recovery from water flooded heterogeneous oil reservoirs, different chemical enhanced oil recovery (cEOR) technologies can be applied. One of the recently developed cEOR technologies for the improvement of oil recovery is based on prefabricated polymeric nano-spheres. These spheres are able to swell over time through absorption of brine. Literature review on the flow of the nano-spheres in porous media showed that the mechanism of oil displacement from heterogeneous as well as homogenous porous media is not well established. One of the proposed mechanisms is that prefabricated polymeric particles might reduce the residual oil saturation Sor (Goudarzi et al. 2014).

To validate this, a series of core flood experiments was carried out in order to study this mechanism in both a heterogeneous Boise outcrop and homogeneous Bentheimer outcrop. Saturation of the cores with highly viscous crude oil was done at 50˚C using the porous plates method. After the oil saturated core was water flooded at 1 ft/day, a bump flood was performed. It helped to achieve the residual oil saturation in the core. Subsequently, several slugs of the nano-spheres were injected into the core in order to study the influence of the nano-spheres on the residual oil saturation. In addition to that, the propagation of the nano-spheres in the core was studied via a pressure drop measurement at different sections of the core and by effluent collection.

The results of the experiments show that the oil displacement from a core with nano-spheres after a bump flood is marginal. Some oil extraction with nano-spheres might have happened due to restricting the flow in the highly permeable zones of the core. The subsequent injection of water could potentially result in improved microscopic sweep efficiency and increased oil production. However, in our experiments this effect was not significant. Our results do not show that nano-spheres significantly reduce the residual oil saturation of the core. Additional measurements showed that the nano-spheres are mostly retained in the inlet section of the core and the propagation of the nano-spheres in porous media is slow. Therefore, the effect of the extra oil recovery is likely limited to the inlet section of the core.

There is currently limited description in the literature on the oil recovery mechanism by polymeric nano-spheres. It has a large impact on how the behaviour of the nano-spheres in porous media needs to be modelled and on the screening of candidate reservoirs for the conditions described in the experiments. In our experiments we have seen no significant reduction of residual oil saturation and slow propagation. Further work is required to evaluate the conditions under which the performance of the nano-spheres can be improved.
Comprehensive Review of Fracture Control for Conformance Improvement in the Kuparuk River Unit - Alaska
Authors: Mishra Ashok , Abbas Sayeed , Braden John , Hazen Mike , Li Gaoming , Peirce John , Smith David D. , Lantz Michael
Published: March 2016

This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
Robust and Efficient Isenthalpic Flash Algorithms for Thermal Recovery of Heavy Oil
Authors: Paterson Duncan , Yan Wei , Michelsen Michael L. , Stenby Erling H.
Published: March 2016

The use of isenthalpic flash has become of interest for the simulation of some heavy oil recovery processes where large temperature changes are experienced. For these thermal simulations energy can be used as a primary variable. This leads to thousands or millions of individual multiphase isenthalpic flash calculations. Robust and efficient algorithms for multiple-phase isenthalpic flash are required to improve the efficiency of compositional simulations for thermal recovery.

The general framework on state function based flash specifications proposed by Michelsen (1999) is applied to general multiphase isenthalpic flash. An extension to the general multiphase case is presented for the two-phase Jacobian. This can be formulated as either a partial Newton or full Newton procedure. An extended solution strategy is presented to deal with many of the problems found in isenthalpic flash. This incorporates Q function maximisation for instances where other methods are not convergent.

Narrow boiling mixtures can be dealt with in the majority of cases without any significant difficulty. This is true of the direct substitution algorithm and the proposed solution procedure. The vast majority of examples can be solved without using Q function maximisation. The challenges associated with multiphase calculations in the Newton steps are investigated. In particular, inadequate initial estimate of the equilibrium type may lead to non-convergent iteration. This can usually be solved by introduction of a new phase and/or elimination of an existing phase. The speed of the method is analysed for a large number of specifications and is found to be only slightly more expensive than isothermal flash in the majority of cases.
Use of Partitioning Tracers to Estimate Oil Saturation Distribution in Heterogeneous Reservoirs
Authors: Dean R. M. , Walker D. L. , Dwarakanath V. , Malik T. , Spilker K.
Published: March 2016

Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations during waterflooding. Compared to core tests, well logs and single well tracer tests, PITTs sample a much larger representative elemental volume (REV) and provide interwell estimates of remaining oil saturation. The test has historically been used to estimate residual oil saturation (Sorw) after waterflooding between injector-producer pairs when the oil is essentially immobile. During polymer flooding, especially with viscous oil, additional oil is displaced and traditional means of interpreting PITTs are not valid. In this paper we present the information gained from conducting a polymer PITT and the saturation estimated during the PITT. This paper presents mechanistic insights into tracer and polymer velocities during the PITT and hence allows for an estimate of remaining oil saturation left behind after polymer flooding and also presents a new log-normal fit which can be used to match multiple flow path responses as is seen in actual field tracer data and reduce the error in estimates of remaining oil saturation. The polymer PITT therefore allows characterization of polymer flood efficiency and is a useful tool in polymer flood evaluations in heterogeneous reservoirs.
Comparison of Strong Alkali and Weak Alkali ASP Flooding Pilot Tests in Daqing Oilfield
Authors: Guo Hu , Li Yiqiang , Gu Yuanyuan , Wang Fuyong , Yuliang Zhang
Published: March 2016

ASP flooding is one of the most promising EOR technologies. Lots of laboratory studies and pilot tests have been finished in Daqing oilfield which is the largest oilfield in China. Comparison of two typical strong alkali ASP (WASP) and weak alkali ASP (SASP) pilots are presented with detained information.

ASP flooding could not only remarkably improve displacement efficiency but also improve sweep efficiency due to the low interfacial tension effect and mobility control technique with help of viscosity enhancement and emulsification effects. The incremental recovery of two ASP was near, while in peak oil production period after the injection took effects, WASP had high oil production rate than SASP. The emulsification effects in weak alkali ASP was weaker than strong one. The chromatographic separation was different in two pilot tests, in which weak alkali ASP had alleviated chromatographic separation. The constitution production sequence was both polymer first, then alkali and finally surfactant. The time gap between surfactant and polymer was about 0.0606 PV for strong alkali ASP, while a respective value of 0.1281PV for weak alkali ASP. Scaling was different and thus anti-scale technique adopted in two pilot tests were a little different. The overall input-output ratio for two tests was different and weak alkali ASP performed much better. Comparison was first made between strong alkali and weak alkali based ASP flooding from field tests perspective. Weak alkali based ASP is proven the development trend.
Measurement of Microemulsion Viscosity and Its Implications for Chemical EOR
Authors: Tagavifar Mohsen , Herath Sumudu , Weerasooriya Upali P. , Sepehrnoori Kamy , Pope Gary
Published: March 2016

We made measurements of microemulsion rheology with mixtures of oil, brine, surfactant, co-solvent, and in some cases polymer to systematically investigate the effects of salinity, co-solvents and polymers. A microemulsion rheology model was developed and used to interpret the experimental results. We show that the optimum microemulsion-to-oil viscosity ratio is roughly 5 to 6 without co-solvent, but it can be reduced to a more favorable ratio of ~2 by adding co-solvent. Even though the amount of co-solvent needed is case dependent, a clear trend of microemulsion viscosity reduction with increasing co-solvent concentration was observed. Limited evidence suggests that large hydrolyzed polyacrylamide molecules with a narrow molecular weight distribution have negligible partitioning to type II and III microemulsions.
Experimental Study of Asphaltene Aggregation during CO2 and CH4 Injection in Shale Oil Reservoirs
Authors: Shen Ziqi , Sheng James J.
Published: March 2016

Enhanced-oil-recovery techniques by gas injection in shale reservoirs have been introduced and investigated. Laboratory and simulation works have shown good results for enhanced shale oil recovery, but one problem with gas injection is asphaltene precipitation and deposition. Damage due to asphaltene precipitation and deposition in conventional reservoirs has been reported in the literature. In shale reservoirs, pore and throat sizes are much smaller than in conventional reservoirs. Thus, large asphaltene aggregates may cause more serious problems in shale reservoirs.

This experimental study used a nanofiltration technique to investigate the size of asphaltene aggregates precipitated during CO2 and CH4 injection in a shale oil sample. Nano membranes of 200nm, 100nm and 30nm were used to filtrate oil samples injected with different mole fractions of CO2 and CH4 gas. The distribution of asphaltene aggregates’ size at different injected CO2 and CH4 concentrations were obtained and compared with the pore size distribution data of shale cores measured by mercury intrusion porosimeters. Results showed that a higher injected CO2 and CH4 concentration caused more asphaltene precipitation and growth in asphaltene aggregates’ size. The precipitated asphaltene particle size was large enough to cause a pore-blocking problem in tested shale cores.
Designing and Injecting a Chemical Formulation for a Successful Off-Shore Chemical EOR Pilot in a High-Temperature, High-Salinity, Low-Permeability Carbonate Field
Authors: Levitt David , Klimenko Alexandra , Jouenne Stephane , Passade-Boupat Nicolas , Cordelier Philippe , Morel Danielle , Bourrel Maurice
Published: March 2016

This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology.

A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity.

The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush.

Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%, Al-Amrie et al., 2015), suggesting that the reason for the lower recovery in reservoir cores was in fact due to the short core length with respect to the mixing zone, as suggested in a previous publication (Levitt et al., 2012).
Experimental Investigation of the Effect of Polymers on Residual Oil Saturation
Authors: Koh Heesong , Lee Vincent B. , Pope Gary A.
Published: March 2016

Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
A Systematic Method for Reducing Surfactant Retention to Extremely Low Levels
Authors: Jang Sung Hyun , Liyanage Pathma Jith , Tagavifar Mohsen , Chang Leonard , Upamali Karasinghe A. , Lansakara-P Dharmika , Weerasooriya Upali , Pope Gary A.
Published: March 2016

The chemical cost to recover an incremental barrel of oil is directly proportional to the surfactant retention, so the single most effective way to reduce the cost is to reduce surfactant retention. The main objective of this research was to demonstrate how surfactant retention could be reduced to almost zero by careful optimization of the chemical formulations for different crude oils. Although surfactant retention has been studied for many years over a wide range of reservoir conditions, its dependence on the rheological behavior of the microemulsion that forms in-situ has not been adequately studied. Thus, in this paper we emphasize the importance of microemulsion rheology and demonstrate how to develop and test formulations with properties that give very low surfactant retention. Novel co-solvents (iso-butanol (IBA) alkoxylates and phenol alkoxylates) were tested in some of the formulations with excellent results. Unlike classical co-solvents used to optimize chemical formulations, the new co-solvents cause only a slight increase in the interfacial tension. A series of ASP corefloods were performed in sandstone cores with and without oil to measure surfactant and co-solvent retention and to elucidate the effects of microemulsion viscosity, salinity gradient, clay content, surfactant concentration and other variables. Dynamic adsorption was measured in cores with the same mineralogy and compared with the retention from oil recovery corefloods to determine the component of the retention due to phase trapping.
Reduction of Residual Oil Saturation in Sandstone Cores Using Viscoelastic Polymers
Authors: Qi Pengpeng , Ehrenfried Daniel H. , Koh Heesong , Balhoff Matthew T.
Published: March 2016

Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM).

Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual oil reduction of 5% OOIP was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very low elasticity (NDe<0.6) did not result in observable reduction in residual oil saturation; however, another 10% OOIP residual oil was reduced when the flow rate was increased (NDe>25). All experiments at constant pressure drop indicate polymer viscoelasticity reduces the residual oil saturation. Results from CT scans further support these observations. A correlation between Deborah number and residual oil saturation is also presented.
Radial and Linear Polymer Flow - Influence on Injectivity
Authors: Skauge T. , Skauge A. , Salmo I. C. , Ormehaug P. A. , Al-Azri N. , Wassing L. M. , Glasbergen G. , Van Wunnik J. N. , Masalmeh S. K.
Published: March 2016

Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.

Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.

Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.

History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
Evaluation of Innovative Associative Polymers for Low Concentration Polymer Flooding
Authors: Alexis Dennis , Varadarajan Dwarakanath , Kim Do Hoon , Winslow Greg , Malik Taimur
Published: March 2016

Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
Three Phase Steady State Flow Experiments to Estimate Microemulsion Viscosity
Authors: Davidson Andrew , Nizamidin Nabijan , Alexis Dennis , Kim Do Hoon , Unomah Michael , Malik Taimur , Dwarakanath Varadarajan
Published: March 2016

Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Predicting Microemulsion Phase Behavior for Surfactant Flooding
Authors: Jin Luchao , Budhathoki Mahesh , Jamili Ahmad , Li Zhitao , Luo Haishan , Delshad Mojdeh , Shiau Ben , Harwell Jeffrey H.
Published: March 2016

The surfactant screening process to develop an optimum formulation under reservoir conditions is typically time consuming and expensive. Theories and correlations like HLB, R-ratio and packing parameters have been developed. But none of them can quantitatively consider both the effect of oil type, salinity, hardness and temperature, and model microemulsion phase behavior.

This paper uses the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior based on the ambient conditions and surfactant structures. By using HLD equation and quantitatively characterized parameters, four optimum surfactant formulations are designed for target reservoir with high accuracy compared to experimental results. The microemulsion phase behavior is further predicted, and well matched the measured equilibrium interfacial tension. Its predictability is then reinforced by comparing to the empirical Hand's rule phase behavior model. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model.

The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.
Development and Field Testing of a Real-Time Casing Collar Locator Technology to Optimize Casing Exit Operations
Authors: Fang Lei , Dahlberg Knut Inge , Lydvo Bjorn , Olsnes Kjetil
Published: March 2016

Operators need a more reliable and efficient method of performing whipstock casing exits, especially in the high cost areas and deepwater environments. Milling through casing collars significantly increases operations time and poses risks for downhole tool failures. In scenarios where casing tallies are inaccurate or missing, wireline Casing Collar Locator (CCL) services are normally utilized to identify casing collar locations to mitigate risks. However, significant rig time is associated with the deployment of wireline service.

A new technology was recently developed to detect and visualize the casing collars in real-time while running in hole on drill pipe with the milling and whipstock assembly. The new capability is developed with the same downhole tool that provides real-time downhole data, such as torque, weight-on-mill, Equivalent Circulating Density (ECD) and downhole dynamics diagnosis, to optimize the milling of the casing window. In combination with the company's Measurement While Drilling (MWD) directional measurements, the technology allows placement of whipstock in an optimal location, orientation of the whipstock and optimized casing window milling in a single run. This new service significantly improves the reliability and efficiency of the casing exit operations, and save the operators substantial rig time, especially in scenarios where a wireline CCL service is otherwise required.

The technology was successfully field tested offshore Norway at the Grane field with a major Norwegian operator. Results from the two field tests from two different sizes of casing exit operations, 18 5/8″ and 13 3/8″, are included in this paper. Casing collars were successfully detected and visualized in real-time and enabled optimal placement of the whipstock. Casing windows were subsequently milled efficiently.
Wireless Reservoir Monitoring Reducing Reservoir Uncertainty During Barents Sea Appraisal - A Case History for Norvarg
Authors: Champion Brian P.
Published: March 2016

Located in the Bjarmeland Platform area of the Barents Sea, Norvarg was discovered by Total in 2011 via wildcat well 7225/3-1, with gas being confirmed in both Jurassic and Triassic formations. A drill stem test (DST) was performed in the Triassic Upper Kobbe formation, but with non-commercial well productivity resulting. The post-DST vision for Norvarg was for stacked heterolithic tidal bar sands connected by large channel sands having better reservoir properties than tested in the first discovery well.

The objectives of the follow-on Norvarg-2 appraisal well, drilled in 2013, included verifying the presence of the channel sands defined from seismic, quantifying the channel productivity and demonstrating the contribution of other Kobbe facies by performing an extended duration pressure buildup (PBU). It was a requirement that the selected PBU monitoring method would allow the well to be permanently abandoned in accordance with Norwegian legislation without any requirement for further well intervention. This was achieved by using an emergent new electromagnetic (EM) wireless reservoir monitoring technology, which allowed the pressure buildup to continue undisturbed beyond the end of the DST and final well abandonment.

EM wireless monitoring technology is already well established as a means to monitor the reservoir pressure and temperature in abandoned appraisal wells, or suspended development wells, for the purpose of interference testing and reducing uncertainties in connectivity. However, this was the first time that it has been directly applied to monitor a long term PBU beyond final abandonment of a subsea appraisal well. By analysing the pressure transient data the objective was to investigate the presence of any flow barriers in the reservoir that might not be detectable during the course of a typical short duration pressure buildup performed during a DST.

This paper presents a case study of the first time application in the Barents Sea of a post-abandonment wireless monitoring solution that successfully delivered high quality reservoir pressure and temperature data for a period of 9 months beyond the end of a DST. Analysis of the data provided clear evidence of internal flow barriers, located 130m and 280m from the wellbore, that were not observed during the normal DST period. This data proved the limited connected volumes and confirmed the requirement for additional development wells, compared with what was known prior to performing the test. This was important information to support the construction of the full field model and the further evaluation of the Norvarg prospect.

Due to poor reservoir properties and disappointing deliverability, no viable development concept was identified for Norvarg, even with an increased well count and using fractured vertical and horizontal wells. The license for PL535 was subsequently relinquished in May 2014.
LWD Formation Fluid Sampler Tool Collects First Fluid Samples While Drilling In Deep Water On The Norwegian Continental Shelf
Authors: Solbakk Tommy , Riise Henrik Erevik , Strøm Ellen Ambjørnsen , House Jerry , Eriksen Kåre Otto , Digranes Gunnar
Published: March 2016

Fluid samples were acquired in an exploration well and subsequent pilot hole for an operator in deep water on the Norwegian continental shelf to identify the reservoir fluids and to check for potential connectivity between two reservoir targets. Several limiting factors meant that pipe-conveyed logging after drilling was not a viable option. Consequently, a logging while drilling (LWD) formation fluid sampling tool was run as a part of a LWD evaluation program to collect fluid samples while drilling and when pulling out of the hole after reaching TD (total depth) of the section.

A team of global and local experts was established to plan the job. The team performed a risk analysis to identify risks and plan mitigating actions. Several challenges were identified, including the potential damage to equipment from vibration when drilling out the shoe track or from hitting stringers while drilling the formation. Other challenges identified involved potential tool movement from rig heave during sampling and required sampling time as a function of the duration of formation exposure to drilling mud before sampling.

The team assessed the risks and established a plan to mitigate them, and the job was performed according to plan in February and March of 2014. A total of nine fluid samples were collected in two well sections, completing each section in one drilling run. This paper discusses the results of the third-party laboratory sample analysis. The formation evaluation logs were inconclusive as to whether or not the reservoir contained oil, condensate, or gas at some depths because of the laminated structure of the formation. The LWD fluid sampling technology confirmed that the reservoir contained gas. This paper also discusses the job planning, mitigating actions that were introduced, implementation and results of the job, and the benefits of fluid sampling while drilling.
Shoe Track Drillout Analysis: Factors Affecting Drilling Efficiency
Authors: Wiktorski Ekaterina , Kaland Thorbjørn , Belayneh Mesfin
Published: March 2016

Drillout optimization is analyzed based on criteria that includes higher rate of penetration (ROP), reduced overall cost per foot, reduced drilling time, and reduced wear rates. In the industry, there are no mechanistic and empirical models used to simulate shoe track drillout optimization. The current common approach is the use of "best practices," which have been developed by companies throughout years of experience. However, even when the best practices are used, shoe track drillout is often time-consuming and damaging to the operation of the drilling tools.

This paper presents analyses of field shoe track drillouts data, obtained from several wells, to assess the primary drilling controlling parameters with respect to drillout times.

The study reveals primary factors that affect shoe track drillout time. It also provides an understanding of how operational parameters should be manipulated to achieve the desired ROP. Finally, the study results were compared to existing best practices. This comparison was used to create a combined list of recommendations that can be consulted before drilling through a shoe track. Although the elimination of damage to the BHA is an important issue in this topic, it is beyond the scope of this paper and may be the focus of future research.
Addressing the Health Risks of Silica Cement: A Custom Solution for Norway
Authors: Johnson Carl R. , Knowles John , Rønnekleiv Bjørn
Published: March 2016

In recent years, a project was initiated to identify a safe and practical alternative to conventional silica-based cement slurries. The objective was to eliminate exposure to respirable crystalline silica (RCS) in oilfield cementing operations. RCS, as well as being linked to various respiratory illnesses (1), has now been identified as a human lung carcinogen (2), implying there is an established link between exposure to RCS and lung cancer.

When cementing well sections with a bottomhole static temperature (BHST) of over 110°C [230°F], a cement powder containing silica flour must be used to ensure the set cement matrix is stabilized to be able to withstand persistent exposure to these temperatures over time (mitigating against strength retrogression). A certain proportion of the silica within these conventional cement blends is classified as RCS.

The newly developed system, known as zero respirable crystalline silica blend or ‘ZRCS-blend’, was successfully applied on numerous occasions on a Norwegian rig. Interestingly, the system found successful application in a batch-drilled conductor campaign on a high-pressure/high-temperature (HPHT) field where the potential exposure during production exceeded 110°C [230°F]. Whilst being a safer alternative to conventional cement systems, the ZRCS-blend was able to deliver a top of cement (TOC) to the seabed on each and every occasion during the campaign, thus eliminating the need for any remedial operations.

As shown by proven success of the ZRCS-blend offshore on the Norwegian continental shelf, the system provides an alternative to silica-based cement for operations worldwide, to comply with regulations and health, safety, and environmental guidelines.
Evolution of a Well Annular Barrier for Mitigation of SCP
Authors: Bårdsen Johnny , Dagestad Vibjørn
Published: March 2016

A novel, Well Annular Barrier (WAB) was introduced back in 2011 as an open-hole, zonal isolation packer. Its strength, ruggedness and pressure capacity over the past four years has proven it a valuable solution. Especially for ensuring the successful cementing of casing strings which were required to be run through challenging environments such as overburden, depleted zones, water bearing sands or unconsolidated zones.

Work is in progress to develop a verification system for WAB expansion and integrity, further growing its capabilities and the operating envelope in which it can be deployed. This will in turn increase the WABs potential applications, and use as a stand-alone, open-hole barrier. The newly developed system consists of pressure and temperature sensors either mounted independently from, or integrated with, the WAB. Annular sealing integrity will be confirmed by direct pressure measurement down-hole. For SCP applications, this will replace indirect confirmation of integrity via cement bond logs, which is the current practice. A verification table in line with requirements outlined in Norsok D-010 has been prepared to comply with industry standards for barrier verification.

The current climate in the oil & gas industry calls for novel solutions to known challenges. Well integrity in the overburden is one such challenge the industry has a high focus on, and solutions must meet a challenging set of requirements. New solutions need to be equal to or better than existing ones, hence qualification requirements and documentation are paramount in delivering innovative solutions. Some operators do not accept sustained annulus pressure in producing wells, especially in HPHT applications. The WAB combined with this new Well Data Monitor (WDM) for verification of pressure seal is an evolutionary step that could eliminate this challenge. It offers a new ‘tool in the box,’ expanding the operating envelope and enabling advanced well construction with no compromises.

This evolution of the WAB can aid to further prevent surface casing pressure (SCP), a huge concern throughout the industry. With the introduction of the WAB with sealing verification, operators can more easily construct robust and safe wells while at the same time, reducing construction time and cost.
Polymers and Polymer-Based Gelants for Improved Oil Recovery and Water Control Applications in Naturally Fractured Chalk Formations
Authors: Hatzignatiou Dimitrios G. , Giske Nils H. , Stavland Arne
Published: March 2016

Water flooding of naturally fractured carbonate (NFC) formations always poses several challenges related to formation sweep, oil recovery efficiency and rate of extraction from matrix blocks, and water management. The presence of natural fractures decreases formation sweep, delays oil recovery rates, and often yields high injector/producer conductive paths which increase produced water cuts with undesirable impacts on fluids production from technical point of view (ranging from lifting difficulties to well stop flowing) as well as economic one (produced water separation, cleaning, and re-injection).

Downhole and deep-reservoir fluids management becomes important to addressing or reducing negative oil production effects in NFC formations. Injected fluid diversion away from well-established high-conductivity flow paths will be extremely beneficial to (a) sweep previously unswept formation regions, (b) reduce circulation of injected water, and (c) improve the oil recovery rate and ultimate recovery factors. Injected fluid diversion gels, used in such applications, are normally based on a polymer/crosslinker mixture designed to gel at a given distance /location away from a treated well. However, HSE regulations and/or surface facilities requirements may not permit in certain occasions the use of such chemical systems that have been tested and successfully field-applied previously.

In this work, existing commercial polymer and polymer-based chemicals that could be used for water management is NFC reservoirs are screened and evaluated in the laboratory. Several testing bulk- and core-based techniques have been used to achieve this goal with the selected chemicals undergone thorough investigation of their filterability, injectivity, gelation time, gel strength, gel shrinkage, and impact on oil production.

Injection of high and low molecular weight HPAM polymers into fractured cores does not hinder the oil production mechanism in chalk formations yielding a lower oil recovery rate but comparable ultimate recoveries with water injection. The environmental friendly polymer (Polymer B) gelant is "inconsistent" related to the formation of gel; when it gels, the quality of the formed gel is poor and provide no resistance to a post-treatment water injection. The non-environmentally friendly polymer (Polymer A) gelant worked consistently concerning gelation and yielded good quality, strong gels that can withstand post-treatment applied pressures during water injection.