bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding Foam Flow with a New Foam EOR Model Developed from Laboratory and Field Data of the Naturally Fractured Cantarell Field
Authors: Skoreyko Fraser , Villavicencio Antonio Pino , Prada Hector Rodríguez , Nguyen Quoc P. 
Published: April 2012

Abstract
As much of the oil in the Akal field of the Cantarell complex is contained in the low permeability oil wet matrix, foam injection has been proposed as a method to control fluid mobility in the fracture, with the possible added benefit of transporting surfactant into the matrix so that additional oil could be liberated through a reduction of interfacial tension between oil and water (if this effect is significant for the surfactant in question). Presented in this paper is the work flow undertaken during an extensive study of all available laboratory experiments and pilot single well foam injection tests. Laboratory experiments ranged from simple water plus surfactant imbibition tests and surfactant flooding tests, to more complex foam flooding in split core experiments and co-injection of surfactant and gas for generation of foam in-situ. There were three field pilot single well foam injection tests that were included in this analysis that were of the huff-and-puff design. This extensive analysis was done with the aid of numerical simulation that resulted in the development of a novel foam model that handles both mobility control and interfacial tension reduction effects, and is capable of simulating foam degradation, foam regeneration, and trapped foam phenomena. Previous foam models available in commercial numerical simulators were not capable of simulating all of these foam effects together. It is shown that with identical foam parameters, this model matches all laboratory core flood studies as well as the field pilot tests, showing that this foam model is capable of predicting foam performance in both laboratory and field settings. The foam components can be chosen to be defined as either gaseous or aqueous components and this choice is shown to affect the impact of capillary pressure on foam flow into the matrix.
Also discussed in this paper are details of how the foam behaves when injected into a gas saturated zone where the foam combines with in-situ gas, resulting in higher foam qualities than was injected. It is demonstrated that foam mobility control as a function of foam quality is an important aspect for matching field performance. The significance of correct foam density calculations is also discussed using field scale models.
The work done to match the many laboratory and field scale foam tests resulted in a significant improvement of the understanding of foam degradation, regeneration, permeability blockage, and flow in porous media and the phenomena responsible for generating incremental oil.
Surfactant-Mediated Spontaneous Imbibition in Carbonate Rocks at Harsh Reservoir Conditions
Authors: Chen Peila , Mohanty Kishore K. 
Published: April 2012

Abstract
The goal of this work is to pursue strategies to improve oil recovery in highly fractured carbonate reservoirs by altering the wettability from oil-wet to preferentially water-wet at high temperature (100°C or above), high salinity, and especially high hardness environments. Cationic surfactants and anionic surfactants were investigated for their compatibility with hard brine and thermal/hydrolytic stability. Sequestration agents were added to improve aqueous solubility. The performance of surfactant formulations was evaluated by measuring contact angles on calcite plates and spontaneous imbibition in originally oil-wet dolomite cores. Cationic surfactants altered the wettability of oil-aged calcite plates towards a more water-wet state in the presence of hard brines; oil recovery by spontaneous imbibition from dolomite cores was 50–65% OOIP. Anionic surfactant formulations changed the carbonate wettability to strongly water-wet only when the brine salinity and divalent ion concentration were reduced. The wettability could be altered in hard brines if a sequestration agent (e.g. EDTA) is added to anionic surfactant formulations; up to 45% OOIP was recovered by spontaneous imbibitions. EDTA provides alkalinity, saponification, chelation of divalent ions, and dissolution of dolomite; these mechanisms are responsible for the increase in imbibition rate and ultimate oil recovery in fractured carbonates.
A New Class of Viscoelastic Surfactants for Enhanced Oil Recovery
Authors: Siggel L. , Santa M. , Hansch M. , Nowak M. , Ranft M. , Weiss H. , Hajnal D. , Schreiner E. , Oetter G. , Tinsley J. 
Published: April 2012

Abstract
A new class of viscoelastic surfactants for chemical enhanced oil recovery is presented. The triphenoxmethanes (TPM) show promise under harsh conditions of high salinity and high temperatures. The TPM's are viscoelastic at low concentrations (&lt;0.5%w/w), show good stability in highly saline brine (18.6% TDS) that contains high concentrations of divalent cations at elevated temperatures (&gt;70°C). Static adsorption measurements show acceptable values for the harsh conditions under study. Rheological measurements demonstrate that the viscoelasticity is not from formation of wormlike micelles and displays non-Maxwell behavior. We propose a novel supramolecular structure that explains the laboratory and rheological observations to date. The compounds show good injectivity into 2 Darcy Gildehaus sandstone
The development of this class of compounds combines the efforts of a team comprised of synthesis, analytics, rheology, core lab and computational chemistry. The goal is to develop an understanding the system's behavior from the molecular level in-silico via computational chemistry, through coreflood tests -and beyond- for a future field pilot. The structure- property-relationships that are being developed will lead to further refinement and targeted development of next generation molecules with improved properties.
Adsorption-Desorption of an Amphoteric Surfactant onto Permeable Carbonate Rocks
Authors: Zhou Xianmin , Han Ming , Fuseni Alhasan B. , Yousef Ali A. 
Published: April 2012

Abstract
The loss of surfactant from aqueous solutions during the propagation in the reservoirs, especially carbonate reservoirs, is one of the major concerns with chemical oil recovery processes. This is due to the loss of effectiveness of the chemical solution to reduce the oil-water interfacial tension and thus renders the process economically unfeasible. This paper presents, in detail, 10 runs of core flooding tests on dynamic adsorption and desorption of an amphoteric surfactant (OCT-1) onto permeable carbonate rocks, which were conducted in natural carbonate core plugs at reservoir temperature of 100°C and pore pressure of 3100 psi. The surfactant solution was continuously injected into the core plug until the effluent surfactant concentration approached that of the injected surfactant solution, followed by seawater injection until no surfactant was present in the effluent. The effluent surfactant concentrations were analyzed by means of titration technique. Amount of dynimc adsorption and desorption of surfactant solutions was calculated using a new definite integral method. The results showed that the adsorption of the surfactant decreases with increase in the value of the pore geometry parameter, (K/Ф)0.5. The adsorption ranges from 0.223 mg/g-rock to 0.597 mg/g-rock for the rocks with permeabilities from 688 md to 110 md. For surfactant concentration of 0.2 wt% OCT-1 in seawater that was used in the study, this level of adsorption implies the surfactant is applicable from adsorption point of view. It was also observed that the adsorption varied with the initial surfactant concentration, as well as relationship between dynamic adsorption and despersion. The value of dispersion, mechanical mixing coefficients and matching adsorption were obtained using dispersion/adsorption equations to match experimental data. This paper presents insights into the adsorption and desorption of the amphoteric type of surfactant on carbonate rocks which could help the application design for a chemical flooding process.
Snorre In-Depth Water Diversion Using Sodium Silicate - Single Well Injection Pilot
Authors: Skrettingland Kjetil , Giske Nils Harald , Johnsen Jan-Henrik , Stavland Arne 
Published: April 2012

Abstract
In-depth water diversion has been evaluated as a measure for increased oil recovery at the Snorre field, offshore Norway. The waterflood sweep efficiency can be potentially increased by in-depth placement of a blocking agent.
From a comprehensive qualification program presented in a previous work (SPE 143836) in-depth formation plugging was demonstrated in realistic core flood experiment using sodium silicate.
This paper highlights key results obtained from a single well pilot injection of sodium silicate in an offshore well at the Snorre field at NCS. The injection pilot was carried out successfully in June 2011 with the goal to confirm the ability of generating an in-depth permeability restriction approximately 40 m away from the wellbore. Fluids mixing and injection were performed from a vessel linked up to the platform in order to minimize the operational interference with the ongoing work on the platform.
The chosen pilot design was aimed to (a) soften the formation water by a KCl preflush, (b) control the gelation kinetics using HCl acid mixed into the diluted silicate solution, and (c) displace the silicate solution by a KCl postflush.
The in-depth permeability reduction was interpreted from injectivity measurements and from repeated pressure falloff-tests before and after the sodium silicate injection. The quality of the response measurement data was very good, and the in-depth permeability reduction was demonstrated with kinetics similar to predictions derived from laboratory experiments. The size of spacer slug applied in front of the sodium silicate was, however, on the low side. A larger spacer slug would probably be more optimal.
Review of Gas Injection Projects in BP
Authors: Brodie James , Jhaveri Bharat , Moulds Tim 
Published: April 2012

Abstract
BP has developed a range of innovative techniques to maximize economic oil recovery from its global miscible gas floods and the results have been reported in a series of publications over the past three decades. The purpose of this paper is to provide an overview of BP's experience of establishing, managing and optimizing a miscible gas flood.
Prudhoe Bay (Alaska) is the world's largest miscible gas project. Conventional and unconventional methods have been applied in a variety of different settings. An extensive surveillance program has facilitated a good understanding of the processes operating at field scale and surveillance data are used to optimize the flood. In 2000, a large-scale gas cap water injection project was implemented to slow the decline in field pressure. This project has made the vaporization process more efficient at higher pressure, resulting in additional recovery. Miscible gas injection has been extended to numerous other fields on the North Slope of Alaska.
BP has two active miscible gas projects in the North Sea: Magnus and Ula. Tertiary miscible water-alternating-gas (WAG) flooding in Magnus field started in 2002 and its impact on reservoir performance is significant and well understood. Tertiary miscible WAG injection in Ula field started in 1998 and has played a key role in arresting production decline. The WAG scheme in Ula is currently being expanded. In addition to these projects, BP operates a CO2 injection and storage project at In Salah, Algeria, where more than 3.2 million tonnes of CO2 have been stored since 2004.
Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so. The potential availability of large sources of CO2 in the future, supplied by carbon capture, could help maintain a leading role for miscible gas injection for years to come.
Research and Application on Nitrogen and Dissolver Assisted Horizontal Well Steam-Injection to Develop Shallow Thin Super Heavy Oil Reservoirs
Authors: Sun Jianfang , Yang Yong , Wu Guanghuan , Jiang long , Cao Qiuying , Zhao Yanbin 
Published: April 2012

Abstract
Chun-feng heavy oil field is located in Junggar Basin, western China. Dead oil viscosity is commonly more than 5×104mPa•s. The depth of the heavy oil play ranges from 400 to 500m underneath with net pay of 2 to 7m. Porosity is about 30% and permeability ranges from 5000 to 6000 md. Traditional development techniques such as steam-injection using vertical well are not effective due to tremendous heat losses, limited heat radius with thin netpay and low drainage energy.
Chun-feng oil field is developed integrally and successfully by using N2 and Dissolver Assisted Horizontal well Steam-injection technology. Peak oil production rate is up to 32t/d, which is 3 times more than that of wells using traditional technologies, and oil-steam ratio is 0.47.
In order to improve steam quality and enhance steam sweep efficiency, new techniques combing horizontal well assisted steam injection with N2 and dissolver are proposed to develop this kind of heavy oil reservoirs. Study also shows that high efficient dissolver may decrease the viscosity of the heavy oil around wellbore and increase injection steam quality; meanwhile, N2 assisted steam injection may increase the volume of injection steam, enhance the drainage energy, and decrease heat losses around wellbore effectively. By the means of plug injection of dissolver and N2 assisted by horizontal wells, super heavy oil may be recovered effectively.
Techniques mentioned above are proved to be very effective for the development of shallow thin super heavy oil reservoirs. Moreover, it is of practical significance which has been proved by successfully applying those techniques to Chun-feng oil field with over 3000* 104t proven oil reserve.
Accurate Modelling of Pore-Scale Film and Layer Flow for Three-Phase EOR in Carbonate Rocks with Arbitrary Wettability
Authors: Al-Dhahli Adnan R. , Geiger Sebastian , van Dijke Marinus I. 
Published: April 2012

Abstract
Three-phase flow is a key to many EOR techniques such as Water Alternating Gas (WAG) injection. Predicting oil recovery during three-phase EOR in carbonates requires a sound understanding of the fundamental flow physics in mixed- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this work we use pore-network modelling, a reliable and physically-based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from mixed to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows accurate modeling of the mobilization of many disconnected phase clusters that arise during higher order (WAG) floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the rock. We validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.
Multiple Foam States and Long-Distance Foam Propagation in EOR Displacements
Authors: Ashoori E. , Marchesin D. , Rossen W. R. 
Published: April 2012

Abstract
Foam reduces gas mobility and thereby improves sweep in enhanced-oil-recovery processes. The "strength" of foam describes the degree of gas-phase mobility reduction. Experiments show that foam can exist in three different states (weak foam, intermediate foam, and strong foam) at the same injection rate. Strong foam with fine bubbles achieves better sweep efficiency than weak foam with coarse bubbles. In experiments, creation of strong foam is triggered by an increase in superficial velocity; thereafter injection rate can be reduced to lower values and strong foam remains at velocities at which weak foam was previously observed.
It is important to determine whether strong foam created near an injection well can propagate to large distances from the well, where superficial velocity is much smaller. Here, we study strong-foam propagation with finite-difference simulations and Riemann solutions, applying a population-balance foam model that represents the multiple steady states of foam.
Our simulations show that strong foam cannot directly displace the initial high-water-saturation bank initially in the reservoir at low superficial velocities; it pushes a weak-foam state with lower velocity that in turn displaces the bank ahead. Our traveling-wave solutions show that strong foam propagates more slowly as superficial velocity decreases and stops propagating at yet lower superficial velocities, in agreement with experiment. Failure of propagation occurs at superficial velocities greater than that at which the strong-foam state disappears; it raises concerns for long-distance propagation of strong foam created near injection well. In the context of the model, it is not extraordinary destruction of foam at the front that slows the propagation of strong foam, but failure of foam (re-)generation at the front. Our model also represents for the first time a process where strong foam is created near the exit of a core and then propagates upstream, as seen in some experiments.
Case Study of Polymer Flood Pilot in a Low Permeability Mannville Sand of the Western Canadian Sedimentary Basin Using Produced Water for Blending
Authors: Irvine Randy , Davidson John , Edwards Scott , Kingsbury Jennifer , Hui-June Park , Tardiff Cara 
Published: April 2012

Abstract
Polymer flooding is well established using fresh waters for polymer hydration. These waters can be difficult and expensive to acquire in some regions and environmental concerns make produced waters attractive alternatives. This case study will summarize the operation of the polyacrylamide polymer pilot using produced water in the Viking Kinsella Wainwright B pool. Particular focus will be put on the treatment of the produced water to make it suitable for polymer hydration.
The pilot has clearly demonstrated that it is possible to generate a stable polymer fluid with the produced water given the high salinity and iron content. The paper will discuss the removal of undesirable elements, control of bacterial growth, compensation for the salinity and handling of the polymer injection fluid to preserve stability.
The target reservoir while having high porosity has low permeability. The permeability to oil averages 95 md which is on the lower end of the traditionally accepted range for polymer flooding. The response of the flood is not definitive but directionally is encouraging. Injectivity challenges have delayed the formation of an oil bank. Production data suggests that the oil bank is starting to develop. The economic viability of the project is indeterminate at this time.
CO2 Injection and CO2 WAG in Dipping Gas Condensate and Oil Reservoirs
Authors: Soroush Mansour , Hoier Lars , Kleppe Jon 
Published: April 2012

Abstract
In this study, different scenarios of CO2 injection in dipping gas condensate and oil reservoirs are investigated through reservoir simulations. Both miscible and immiscible flooding conditions were investigated for a range of different injection gas mixtures, and geological realizations.
We find particularly interesting results for miscible flooding of gas condensate systems below dewpoint pressure. Here, dropped out condensate is the prime target for enhanced recovery projects and multi-contact miscibility could develop through the combined condensing/vaporizing mechanism.
Different patterns of permeability variation with depth in layering scenarios with dip angle showed distinct different responses on produced condensate. CO2 WAG in partially depleted gas condensate reservoirs seems to have the same value of oil recovery in early times, but ultimate recovery is different according to layering heterogeneity. In the case of pure CO2 injection, both up-dip and down-dip, it was found that homogeneous layering showed highest recovery. Here developed multicontact miscible oil-bank is able to move and sweep condensate above it easier. Applying various gas injection mixtures of CO2 and C1 combinations, the effect on ultimate recovery were studied. In this case CO2 injection is above minimum miscibility pressure (MMP) resulting in high recoveries.
CO2 WAG in dipping oil reservoir was also studied extensively, based on injection pattern, MMP values and various layering systems. CO2 WAG in scenarios with increasingly trend of permeability with depth had the highest value of recovery. This is because of prevention from early gas breakthrough in upper layers and good sweep efficiency in lower layers. Pure CO2 injection with total same injection volume showed lower recovery. This may verify that gravity in WAG water injection period is the most effective parameter in the case of down-dip WAG.