bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of simulation and optimisation models for WRP with PIs
Authors: Farhangi Mahsa , Bozorg-Haddad Omid , Mariño Miguel A.
Published: April 2012

Reservoirs play a vital role in the supply of water, especially in drought periods. By optimally operating reservoirs, target objectives can be achieved to acceptable levels. However, the optimal operation of large-scale water resource systems through the use of optimisation models is complicated, time-consuming and sometimes inapplicable, and thus the use of other methods that yield satisfactory near-optimal results with acceptable precision seems to be an attractive solution for this type of problem. This paper compares the performance of ModSim and Weap simulation models with that of Lingo optimisation packages for both single-reservoir and multi-reservoir systems in a period of low flow. For a better evaluation of the models' performance, criteria are developed and applied to the reservoir systems considered in this study. The results show that by considering volume reliability as an operation goal, optimisation models can be replaced by simulation models in single-reservoir systems. However, for such systems, simulation models improve the shortage index about 38% but the temporal reliability, resilience and vulnerability of the system yielded by simulation models are about half the values obtained by optimisation models. Moreover, volume reliability and resilience of the simulation and optimisation models in a multi-reservoir system show a difference of about 25% and 40% respectively. The difference is more than 300% when using other performance indices.
Effects of changing rainfall patterns on WSUD in Australia
Authors: Beecham Simon , Chowdhury Rezaul
Published: April 2012

Bioretention basins and permeable pavements are two widely implemented water sensitive urban design (WSUD) technologies. While their applications are extensive, their effectiveness as a result of changes in rainfall patterns is an emerging and important research question. This paper describes how these systems behave under varying rainfall conditions in Australian cities. To illustrate this, two design parameters, namely emptying times for permeable pavements and scour velocities for bioretention systems, were investigated. The study revealed that there are two groups of cities displaying almost similar peak flow characteristics – high (Darwin, Cairns, Brisbane, Townsville and Sydney) and low (Alice Springs, Hobart, Melbourne, Perth and Adelaide). It was shown that selection of an optimal storage size to ensure appropriate emptying times for permeable pavements requires a balance between managing dry periods, reuse demand and economic considerations. Increase of high flows increases the risk of scouring in bioretention basins, which is particularly significant for the first group of cities. Finally, the paper describes the importance of peak flow estimation method and appropriate selection of modelling time step for sustainable implementation of WSUD in Australia.
Briefing: Water surface profile over side weir in a trapezoidal channel
Authors: Vatankhah Ali R.
Published: April 2012

Side weirs or lateral weirs are widely used for water level control in water treatment plants and irrigation and drainage systems. The side weir is a fixed structure installed at one side of a channel to divert flow laterally. Computation of the water surface profile along the side weir is essential in determination of the discharge over the side weir. An analytical solution of the dynamic equation for spatially varied flow with decreasing discharge, in prismatic channels with a side weir, is available in the technical literature only for the special case of a rectangular channel based on the constant specific energy assumption. However, in irrigation networks, the most common irrigation channels are of trapezoidal cross-section. This paper presents an elegant analytical solution for establishing the water surface profile along a side weir in a trapezoidal channel. Since triangular and rectangular cross-sections are special cases of the trapezoidal cross-section, the proposed analytical solution is also applicable to these cross-sections. The solution, which yields a direct computation of the flow profile in subcritical and supercritical flow regimes, should be a useful engineering tool for the evaluation and design of side weirs in open channels.
Improving Volumetric Efficiency in an Unconsolidated Sandstone Reservoir with Sequential Injection of Polymer Gels
Authors: Saez M. , Paponi H. , Cabrera F. , Muñiz G. , Romero J. , Norman C.
Published: April 2012

In March 2008 Petro Andina Resources implemented the first polymer gel treatment in an unconsolidated sandstone reservoir in Argentina's northern Patagonia. The project was implemented in the Jagüel Casa de Piedra and El Corcobo Norte fields, located in the Neuquen basin. Oil production began in November 2004 followed by water injection project approximately one year later for pressure support. However, sand production and the generation of wormholes resulted in severe water channeling detrimenting volumetric efficiency. Tracer studies confirmed rapid transit times between injector and offset producers in patterns with an average well spacing of 280 meters.

The first conformance pilot occurred in 2008 with a non-conventional polymer injection procedure that included a series of small volume, high concentration gel slugs followed by a short shut-in period. The objective of this strategy was to allow the gelation reaction to occur before reaching the offset producing wells. Successive gel slugs were placed behind the initial gel injection in order to block a significant volume of the highest permeability wormholes. Extensive diagnostics were applied before and after the initial polymer gel treatment, including tracers, monitoring of injection pressure and analysis of fluid production data. Based on a sustained WOR reduction from 6 to 1 in the pilot project after approximately one year, nine additional conformance gel treatments were implemented as of May 2011.

The treatment designs were modified in successive projects based on lessons learned during preceding conformance campaigns. One of the major challenges was to reduce the incidence and consequences of gel breakthrough in offset producing wells.

The paper will discuss the reservoir diagnostics that led to the selection of polymer gel as a method used to mitigate severe water channeling in this unconsolidated sandstone reservoir and the evolution of the conformance strategies applied in subsequent treatments from 2009 to 2011.
Application of a Novel Amylum-Cellulose Nutrient System for Microbial Flooding in Dagang Oilfield, China
Authors: Feng Qing-xian , Cheng Hai-ying , Ma Xian-ping , Dong Han-ping , Ma Ting
Published: April 2012

Microorganisms inhabiting oil reservoirs can be used for microbial enhanced oil recovery (MEOR) due to their high adoptability and ability to produce oil-releasing metabolites in-situ. The compositions and function of the nutrient injected for stimulation of microbial activity is one of the keys to successful the technology. In our previous studies, we found that depletion of nutrient blend due to presence of "thief zone" with high rock permeability, led to insufficient activity of indigenous microorganisms in reservoirs. Eventually the poor additional oil production was observed. Novel multi functional amylum-cellulose nutrient was developed in this study to provide both nutrition for microorganisms as well as material for modify profile.

Reservoir physico-chemical characteristics, concentration of nutrients and microbial activity were surveyed systematically. It was shown, that nutrient activated microbial growth under aerobic and anaerobic condition, and hydrocarbon oxidizing bacteria and fermentative microorganisms played most considerable roles in microbial consortia. Microorganisms were able to oxidize oil to CH4 and CO2 with excretion hydrocarbon emulsifiers and other biosurfactants (rhamnoilpid with C6-C12 long chain fatty acid). Heterogeneous sandpacked column model with three stages nutrients flooding release delaying nutrient solution breakthrough front and enlarged effect range of microorganisms due to viscosity production, particles of cellulose and zoogloea on surface of cellulose particle while bacteria growth. Synergetic MEOR effect of the thief zone plugging and local oil displacement resulted in 15-20% increase of oil recovery in comparison with regular water flooding.

The field pilots were carried out in blocks. Special nutrient (75 tons) was injected and followed by monthly injections of 32000 cubic meters of air/water blend. The shift in microbial activities and other reservoir parameters was monitored. The injection water pressure was increased 2.2MPa and 5075 bbl of oil was increased.
Upgridding Under Multiphase Flow Conditions
Authors: Kelkar Mohan , Sharifi Mohammad
Published: April 2012

Due to advances in computer technology, geo-scientists are increasingly able to build reservoir models which can incorporate significant geological details. It is not unusual to find geological models which contain millions of cells. Flow simulating such models is still a challenge as running a typical simulation model takes two orders of magnitude more time than generating a geological model. Upgridding the geological model to reduce the number of grid blocks while maintaining the essential heterogeneity details to preserve the dynamic performance is the only solution to this problem.

In the literature, many solutions are proposed to upgrid the geological model. The simple static solutions involve combining layers with similar static properties so that the heterogeneous details are preserved. In our paper, we take the method one step further. It has been observed in the past that upgridding should be dependent on the flow process. That is, the way the layers are combined would be different for depletion drive compared to water flooding. The displacement of fluids is strongly dependent on the type of drive; hence, rearrangement of the fine scale layers has to be different to capture this behavior.

In our approach, we propose a method of upgridding which can be applied for either secondary or tertiary recovery processes. Our method is analytical and is based on an idea that fractional flow of a fine scale model has to be preserved on a coarse scale. We use fractional flow on a fine scale model and define our error as the difference between fractional flows of a coarse scale vs. fine scale. We combine layers which minimizes this difference. Using our procedure, we demonstrate that for favorable mobility ratio, it is better that we isolate low permeability layers; whereas, for adverse mobility ratio, we need to isolate high permeability layers. Using both synthetic and field cases, we demonstrate that our proposed method provides superior upgridding compared to other methods currently available in the literature.
New Insights into Clay Swelling: Supercritical CO2 Interaction with Montmorillonite
Authors: AlOtaibi Fawaz M. , AlKhaldi Mohammed H. , Funk Jim J. , Shen Shouwen X.
Published: April 2012

Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.

The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR). Additionally, environmental scanning electron microscope (ESEM) analysis was used to explore the effect of liquid-like CO2 on clay structure of both dry and hydrated Ca and Na- montmorillonite clays.

Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca- montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d- spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2 for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Studies On Foam Flooding EOR Technique For Daqing Reservoirs After Polymer Flooding
Authors: Qingfeng Hou , Zhu Youyi , Luo Yousong , Weng Rui
Published: April 2012

Most of the high permeability reservoirs in Daqing oil field have been conducted by water flooding and polymer flooding.

The average oil recoverable recovery has reached to 53% after polymer flooding. Currently, the further development of such reservoirs has become a big challenge due to both serious heterogeneity reservoirs and highly dispersed residual oil. Foam flooding, as a candidate EOR technique integrating both properties of gas injection technique and chemical flooding, has been proposed. In this study, systematic laboratory experiments on foam flooding EOR technique for Daqing reservoirs after polymer flooding have been performed.

Several operating parameters have important influences on the recovery efficiency. ➀ Both the foamability and stability are the key factors to ensure high performance of recovery. The foam formulas were optimized with good performance of foamability and stability. ➁Injecting mode is another important factor. Three main injection modes, including co-injection of gas and solution, alternative injection of gas and solution, and direct injection of foam were compared. The direct injection of foam is the most effective mode and the alternative injection of gas and solution is the poorest. ➂The gas liquid ratio can also affect the flooding efficiencies greatly. The optimized gas liquid ratio was proposed as 3:1–4:1 for direct injection mode at the reservoirs condition. EOR effect evaluation of foam flooding after polymer flooding has been conducted upon three-layer positive rhythm sandpack cores flooding tests. Results indicate that foam flooding can contribute 12–22% OOIP recovery even if the recovery after polymer flooding is nearly 55%. The obviously increasing of injection pressure during the foam flooding indicates that nitrogen foam flooding has excellent profile control ability.

Foam flooding can block thief zones for highly heterogeneous reservoirs. It may become a promise EOR method for Daqing reservoirs after polymer flooding.
Assessment of Foam for GOR Control to Optimize Miscible Gas Injection Recovery
Authors: Cubillos Helber , Montes Jesús , Prieto Carlos , Romero Pedro
Published: April 2012

Miscible gas flood in a CEPSA-operated oil field has matured and, over the years, oil has been produced at an increasing gasoil ratio (GOR). Even though the gas displacement mechanism is miscible, or close to miscible, the poor mobility ratio between injected gas and displaced oil has led to inefficient sweep of the reservoir.

The use of foam for gas mobility control is a proven IOR technology that can greatly improve gas injection conformance and hence improve volumetric sweep efficiency in secondary or tertiary recovery processes. This paper presents the results of comprehensive laboratory studies undertaken to define a foam system that will reduce gas mobility and preclude any risk of affecting formation injectivity.

We evaluated four surfactants to establish the Foaminess, Mobility Reduction Factor (MRF) and impact of hardness, oil presence and surfactant concentration on foam strength: AOS C12-14 and AOS C14-16, LAS and Fluorobetaine. We found AOS C12-14 and AOS C14-16 to be the best foamers under screening conditions (60 bar, 90 °C): both significantly reduced mobility. AOS was not brine-sensitive but in the presence of oil, the foam performance was reduced. Optimum concentration regarding cost and effectiveness was found to be 5000 ppm. We demonstrated that strong foam can be formed under reservoir conditions (200 bar, 96 °C), using the Surfactant-Alternating-Gas injection technique.

We have submitted a request for approval of a field pilot test which will be the first application of foam as an IOR technology in this field. If success is demonstrated in the field, the proposed approach should be helpful for field operators facing similar production optimization challenges or, for example, Foam-Assisted Water Alternating Gas (FAWAG) projects.
Visualization of Oil Recovery by CO2-Foam Injection; Effect of Oil Viscosity and Gas Type
Authors: Emadi Alireza , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun
Published: April 2012

CO2 injection is a well-established enhanced oil recovery technique which has been successfully applied in conventional oil reservoirs where it can vaporize light hydrocarbon components and displace the oil miscibly. In heavy oil reservoir, CO2 does not develop miscibility but it can significantly promote recovery by dissolving in the oil and reducing its viscosity. Heavy oil viscosity reduction upon mixing with CO2 can be substantial and reductions up to two orders of magnitude can be achieved. However, displacement of viscous and heavy oil by CO2 is generally perceived as being inefficient and hence, very limited number of heavy oil fields have been considered for CO2 injection. There are two main reasons for this; (1) the large viscosity contrast between heavy oil and CO2 which results in viscous fingering and; (2) the slow rate of CO2 diffusion in heavy oil.

The use of CO2 foam represents an opportunity to reduce mobility of CO2 and improve sweep efficiency and at the same time facilitate CO2 dissolution by increasing the contact area between the oil and CO2. The application of foam injection for enhanced heavy oil recovery has not been widely reported in the literature and hence the potential of foam for improving heavy oil recovery is by and large untested.

In our previous works, we reported a series of micro-scale visualization experiments to investigate potentials of sub- critical CO2 and CO2-foam injection for recovery of a medium-heavy crude oil. The results showed that if strong CO2-foam forms in porous medium, it can drastically increase the rate of oil recovery and reduce the residual oil saturation. This paper presents the results of a new series of visualization experiments to investigate the performance of sub-critical CO2-foam for recovery improvement in an extra-heavy crude oil. In the first part of this paper, the effect of oil viscosity on oil recovery and displacement mechanisms has been investigated. The results show that while foam can significantly accelerate and improve oil recovery by CO2 injection, the increase in oil viscosity slows down the process of oil recovery by CO2-foam and may result in weakening of some of the pore scale displacement mechanisms.

In the second part of the paper, the results of an experiment conducted using the same extra-heavy crude oil and surfactant with N2-foam (instead of CO2) is presented. The results show that despite forming strong foam in the porous medium, the oil displacement process is much less efficient during N2-foam injection compared to CO2-foam. The results clearly demonstrate the potential of CO2-foam for enhancing heavy oil recovery for very viscous crudes as a technically viable non-thermal oil recovery method. The results of these experiments significantly improve our understanding of the processes involved in heavy oil recovery by CO2-foam and the pore scale differences with the example of N2-foam injection.
Investigating Low-Salinity Waterflooding Recovery Mechanisms in Sandstone Reservoirs
Authors: Aladasani Ahmad , Bai Baojun , Wu Yu-Shu
Published: April 2012

Numerous core-flooding experiments have shown that Low-Salinity Water Flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery mechanisms remain highly contentious primarily because of the absence of crucial boundary conditions. The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery mechanisms in sandstone reservoirs. The summary of 411 coreflooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) Even though statistical correlations of the residual oil saturation to chlorite (0.7891) and kaolinite (0.4399) contents, as well as the wettability index (0.3890), are comparably strong, the majority of dataset entries are missing, and a prediction model cannot be generated; (2) If a prediction model is generated without clay content values and a wettability index, even though LSWF emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model's regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery mechanisms are governed based on the initial and final wetting states. In strong water-wet conditions, the increase in oil relative permeability is the underlying recovery mechanism. In weak water-wet conditions, the incremental recovery of LSWF is driven by low capillary pressures. In weak oil-wet conditions, the primary LSWF recovery mechanism is the increase in oil relative permeability, and the secondary mechanism is the change of the non-wetting phase to oil. In strong oil-wet conditions, the underlining LSWF recovery mechanism is the increase in oil relative permeability. In all cases, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery however that is rapidly overshadowed by the increase in oil relative permeability and decrease in contact angle.
Gel Dehydration by Spontaneous Imbibition of Brine from Aged Polymer Gel
Authors: Brattekås B. , Haugen Å. , Graue A. , Seright R. S.
Published: April 2012

This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.
Mechanistic Modeling of the Benefit of Combining Polymer with Low Salinity Water for Enhanced Oil Recovery
Authors: Mohammadi Hourshad , Jerauld Gary R.
Published: April 2012

It has long been recognized that there are synergies between EOR (enhanced oil recovery) techniques, as is the case between low salinity waterflooding and polymer flooding. While polymer flooding is a proven technology which improves waterflood recovery efficiency by increasing the water-oil viscosity ratio, low salinity EOR is an emerging technology which enhances the displacement efficiency by changing wettability. One would expect the combined EOR schemes to be at least additive because they target different things. For other reasons, the combination of these two technologies can expand their range of application.

Polyacrylamide polymers widely used in chemical EOR hydrolyze at high temperatures and precipitate if calcium concentration is above 200 ppm. The use of low salinity EOR can make the use of polyacrylamide polymers feasible up to reservoir temperatures of at least 100°C or enable the use of polymers with larger degrees of hydrolysis. Polyacrylamide solution viscosity increases as salinity decreases so OPEX will reduce due to lower required polymer concentration. One third or less of polymer is required with low salinity waterflooding EOR compared to conventional water flooding.

We demonstrate that addition of polymer enhances recovery efficiency and timing of low salinity waterflood. The incremental oil recovery between the homogeneous and heterogeneous cases is close, especially for more viscous oil. At high oil viscosity, combination of low salinity injection water and polymer gives incremental oil recovery about equal or better than the summation of each if used separately. We demonstrate that both secondary and tertiary combined processes are effective but secondary gives better timing. Synergistic behavior of combined processes is more effective in tertiary flood than the secondary cases. Chemical cost comparison of the cases studied shows that a 5-time reduction in chemical cost per barrel of oil recovered can be expected when polymer is added to low salinity. We show that operational constraints in field application can limit the synergy between these combined processes.
A New Dynamic Wettability Alteration Model for Oil-Wet Cores During Surfactant Solution Imbibition
Authors: Kalaei M. Hosein , Green Don W. , Willhite G. Paul
Published: April 2012

Wettability modification of solid rocks by using surfactants is an important process that is used in practical applications such as oil recovery from reservoirs. When wettability is altered, both capillary pressure and phase relative permeability change wherever the porous rock is contacted by surfactant. Due to the complexity of reservoir rock, alteration of the wettability is not uniform throughout the swept area. Although there are several numerical studies in the literature to simulate the effect of wettability alteration on oil recovery from oil-wet rock systems, these wettability alteration models permit alteration of the rock wettability uniformly and independently from time. Properties such as capillary pressure, oil and water relative permeability, and interfacial tension are calculated by the use of an interpolation scaling factor between two wettability extremes: oil-wet and water-wet.

In the present study, a novel time-dependent wettability alteration model is proposed in which the contact angle is correlated to the surfactant concentration through an empirical correlation developed by using experimental data. The model allows the rock wettability to be altered in a heterogeneous manner with time. The proposed model was tested against a number of experimental and simulation results. Very good quantitative agreements between the simulation outcomes and experimental data from the literature were shown. The simulation of surfactant solution imbibition in laboratory scale cores using the proposed new model showed that the wettability alteration should be considered as a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. Also, we found that gravity force is the primary cause of surfactant solution getting into the core and changing the rock wettability toward a less oil-wet state.
Application of a Thermally Activated Particle System for Improved Sweep Efficiency in a Multilayer, Geologically Complex Waterflood
Authors: Mustoni J. L. , Cabrera F. A. , Manrique E. J. , Norman C. A.
Published: April 2012

The Cerro Dragon (CD) Field, located in the San Jorge Gulf Basin (SJGB) of Argentina, offers a significant opportunity for improved volumetric sweep efficiency because of an adverse mobility ratio and spatial anisotropy, typical of the multilayered channels deposits of SJGB. The center of these channels becomes a highly conductive "thief zone", resulting in preferential channeling of injected water to the offset producers without creating an oil bank. As a consequence, sweep efficiency is reduced and operating costs are increased due to the handling of large volumes of produced water. These thief zones are the target for improved reservoir conformance using a thermally activated particle technology known as BrightWater® (BW), developed and patented by BP, Chevron and Nalco Company.

Testing of deep reservoir conformance in Argentina utilizing the BW technology began in 2006 with pilots in the Piedra Clavada and Koluel Kaike fields (Mustoni, et al., 2010). Screening, design and implementation of the BW conformance project in the CD Field was the result of experience gained from these earlier applications. The CD Field conformance project represents a larger scale application of the BW technology in terms of number of wells treated, layers per well, oil reserves, and treatment volumes.

This paper describes the methodology utilized to evaluate and rank BW conformance candidates from a database of more than 100 blocks in the CD Field. A detailed discussion of the candidate selection methodology will be presented, including laboratory testing, chemical formulation and volumes, well surveillance, inter-well tracer, and simulation studies.

This paper will also describe details of internally developed processes that optimized the logistics of field implementation, including simultaneous injection of the chemical solution in multiple injection wells and multiple subsurface mandrels.
Study and Field Application of Organic/Inorganic Cross-Linking Blocking Agent for High Temperature Reservoir
Authors: Dai Caili , You Qing , Liu Xuezhe , Wu Wenming , He Long , Zhao Fulin
Published: April 2012

Polymer gel is widely used for conformance control nowadays, but it is not suitable for high temperature reservoir (over 100 celsius degree). In order to solve the above problems, a novel organic/inorganic cross-linking blocking agent is proposed and developed in this paper combined the advantages of organic and inorganic blocking agents. This novel organic/inorganic cross-linking blocking agent is composed of organic resin, silicide and stabilizer. The optimized formula of this agent at 130 celsius degree was screened through gelation performance and thermal stability in the lab. The appropriate mass fraction of organic resin was 4%~7%, the silicide was 1%~5% and the stabilizer was 0.1%~0.3% in the formulas. It is also confirmed that this novel agent is comfortable for in-depth profile control in 100~140 celsius degree reservoir with gelation time of 8~60 h and there is no dehydration phenomenon at 130 celsius degree aging for 3 months. Sand-packed core experiments indicate that this novel agent has good blocking performance, which can further enhance oil recovery. This novel agent had been applied in production well in Oct 2010, by late 2011, the accumulated oil increment is 3081.5 t, the water cut decreased from 98.7% to 80.5% and the input-output ratio is up to 1 : 3.6. The success of field test confirmed that this novel organic/inorganic cross-linking blocking agent is quite suitable for controlling water and has a broad application prospect.
ASP Formulation Design for Heavy Oil
Authors: Zhang Jieyuan , Ravikiran Ravi , Freiberg David , Thomas Charles
Published: April 2012

The objective of the work detailed was to develop an alkaline-surfactant-polymer (ASP) and achieve good oil recovery at low surfactant concentrations. A combination of phase behavior tests, interfacial tension (IFT) measurements (by spinning drop tensiometer) and coreflood tests were used to develop a solution for an oil that had an API gravity of 15 and viscosity of 2,000 cP.

The percentage of heavy oil in world oil production continues to rise as more light oil reservoirs have either depleted or reached their economic limit. However, the recovery factor from heavy oil reservoirs by both primary and secondary production is low, making these reservoirs candidates for chemical EOR technologies.

Phase behavior tests were used as the primary screening method to identify surfactant formulations qualitatively and the promising candidates were validated by IFT measurements (between the surfactant solution and oil) at different salinities to identify the lowest IFT formulation. Static adsorption tests with reservoir core material were used as a further screening step to ensure formulation was a viable option. Finally, linear coreflood tests were performed at reservoir temperature to validate the formulation and optimize chemical concentration. In one coreflood, 80% of waterflood residual oil was recovered using only 0.15% total surfactants and 2,000 ppm polymer.

The success of the ASP coreflood validates the ASP design for this heavy oil. Typically, heavy oil reservoirs may require lower surfactant concentrations due to higher permeability. As a result, such projects could potentially have a higher reward- risk ratio than ASP projects in conventional oil reservoirs.
Importance of a Second Liquid Phase Formation in CO2 Injection into Bitumen Reservoirs and its Effect on Production
Authors: Feizabadi Seyed Ali , Abedi Jalal , Chen Zhangxin
Published: April 2012

The injection of different solvents, such as propane and CO2, into bitumen, has proven to be an effective method in the production of these kinds of reservoirs. However, in some cases, the prediction of large solvent requirements can make it uneconomical. The formation of a second liquid phase has been observed when the solvent is propane or CO2, with the second liquid phase mainly composed of the solvent itself.

The objective of this research is to understand the importance of this second liquid phase and its effect on production. Also, a simulator that can allocate an individual phase to this liquid phase would allow for prediction of the amount of solvent that can be produced and recycled. This makes the cost evaluation of solvent injection processes to be more realistic.

Depending on the reservoir fluid distribution, a three- or four-phase flow can occur in the absence or presence of water. A compositional simulator based on an equation of state is designed to simulate these multiphase situations. This simulator has a four-phase flash and stability subroutine, which make it more realistc compared to other compositional simulators. In fact, it can handle a maximum of three hydrocarbon phases and one aqueous phase. Relative permeability plays an important role in multiphase flow; numerical results indicate that, by increasing the number of phases, there is an increase in project life.

It is valuable to mention that the results of this research can be also used in CO2 sequestration.
Surface Complexation Modeling for Improved Oil Recovery
Authors: Brady Patrick V. , Krumhansl James L. , Mariner Paul E.
Published: April 2012

Coordination chemistry models of oil adhesion to sandstones and calcite allow more precise testing of wettability alteration theories. The primary electrostatic bonds calculated to link oil to most sandstones are oil -NH+ and kaolinite edge >Al-OH2+ sites at pH < 5.5, and oil -COOCa+ and kaolinite edge >Al:Si-O- sites at pH > 5.5; −NH+ and −COOCa+ can also exchange onto basal planes. Low salinity waterfloods should break −NH+ — >AlOH2+ bonds at pH < 5.5 and low salinity, low Ca+2 waterfloods are calculated to eliminate −COOCa+ — >Al:Si-O- bonds at pH > 5.5. Oil is calculated to link electrostatically to calcite through oil − COO- and >CaOH2+ sites, and to a lesser extent through oil −NH+ and calcite >CO3- sites. Sulfate- rich floods are calculated to eliminate >CaOH2+ charge through sulfate sorption. Divalent cation (Ca+2 and Mg+2) – rich floods are calculated to reverse −COO- charge through sorption.
A New Method for Dynamic Calculation of Pattern Allocation Factors in Waterflood Monitoring
Authors: Saadatpoor Ehsan , Karami Hossein , Al-Ajmi Moudi Fahad
Published: April 2012

Successful operation of a waterflood requires the ability to make informed decisions based on pattern voidage replacement ratio (VRR), watercut, and water production rate. These performance measures are calculated from actual performance data using predefined allocation factors. In a pattern, there are several producers, each contributing to the total pattern production. The percentage of total volume produced from each producer is called the allocation factor.

Waterflood performance is commonly monitored and studied using static allocation factors. The monitoring workflow uses the injection and production data from a database, and pattern allocation factors are assigned to production wells as static values based on geometry of waterflood patterns. In fact, the pattern allocation factors are set as a fraction of the area of a circle exposed to that pattern; hence they are constant. The allocation factors will not represent the real physics involved if they are determined based merely on geometry of patterns. Some important parameters, such as water injection rates of patterns, have a major effect on allocation factors. Based on specific assumptions, we have developed equations to define a new allocation factor for production wells.

The dynamic method proposed in this paper includes several parameters that affect patterns—including well radius, distance between wells, and injection rates—and leads to more realistic waterflood monitoring and more efficient decision making with no extra cost or time needed for data gathering or model development and simulation. The effect of using new allocation factors was studied on actual field data, and results verified the possible improvement in performance if dynamic allocation factors are used.
Wettability Survey in Bakken Shale Using Surfactant Formulation Imbibition
Authors: Wang Dongmei , Butler Ray , Zhang Jin , Seright Randy
Published: April 2012

For ultra-tight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. In our previous study for Bakken shale imbibition, a group of surfactant formulations were examined—balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to increase oil production from shale with ultra-low porosity and permeability in the Middle Member of the Bakken Formation in the Williston Basin of North Dakota. To advance this work, this paper determines the wettability of different parts of the Bakken Formation. One goal of this research is to identify if the wettability can be altered using surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.

Using modified Amott-Harvey tests, the wettability was determined for cores from three wells at different portions of the Bakken Formation. The tests were performed under reservoir conditions (90-120°C, 150-300 g/L formation water salinity) using Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction to the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided EOR values of 6.80% to 10.15% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.65% to 25.40% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken Formation. For comparison, recovery factors using the existing production methods are only on the order of a few percent OOIP. Positive results were generally observed with all four surfactants: 17A, 58N, S2, and C1. From our work to date, no definitive correlation is evident in surfactant effectiveness versus (1) temperature, (2) core porosity, (3) whether the core was from the Upper Shale or the Middle Member and (4) whether the core was preserved (sealed) or cleaned prior to use.
Microbial EOR: A Quantitative Prediction of Recovery Factor
Authors: Lacerda Eduarda C. , Priimenko Viatcheslav I. , Pires Adolfo P.
Published: April 2012

Microbial Enhanced Oil Recovery (MEOR) is a promising EOR technique. Feeding bacteria so that they can be stimulated to produce metabolites is a good way to increase recovery factors. In this paper, we present a mathematical model which describes a MEOR process and can be applied to estimate the recovery factor.

A one-dimensional isothermal model, comprising displacement of oil by water containing bacteria and nutrients, is studied. The model is composed by a hyperbolic system of four partial differential equations with source terms and appropriate initial and boundary conditions, solved numerically by a fractional step method. We analyse the case when the produced metabolites are biopolymers which increase water viscosity, and then, improve sweep efficiency.

The required parameters used in this model are not always known, therefore, to better investigate their importance, a sensitivity analysis is run and the impact in the recovery factor observed. The sensitivity analysis was performed according to the following steps:

three values for the maximum specific growth rate were assumed and their impact in the recovery factor is analyzed, to demonstrate the importance of bacteria screening; water viscosity dependence on biopolymer concentration is described by three functions and the resulting recovery factor of each one of them is compared; three different models describing bacteria growth and their effects in the recovery factor are also presented.

Maximum specific growth rate was the parameter that has caused the major impact in the recovery factor. When a small value was adopted, there was no additional oil recovery in comparison to water injection. This sensitivity analysis has shown the importance of laboratory tests to improve the prediction of recovery factor. It was also noticed that a significant incremental oil recovery can be achieved with this process of MEOR for different oil viscosities.
Managing Risk in the Deployment of New Technology - Getting LoSal EOR into the Business
Authors: Reddick C. , Buikema T. , Williams D.
Published: April 2012

This paper documents key learnings from BP's experience in managing the risks associated with deploying LoSal waterflooding technology over the past five years. The paper covers the management of technical risk, operational risk, organisation and resourcing risk, and the risk of failing to secure adequate engagement with decision-makers.

The learnings described in the paper cover experiences gained over multiple projects over different stages of project cycles, including the application of LoSal EOR in onshore and offshore settings, in existing waterflood operations as well as new projects.

On the technical side, the derivation of quality coreflood data, and its calibration with both pilot and single well chemical tracer test data have been key for building confidence in the magnitude and uncertainty of the LoSal response.

Operational risk management has been essential for securing approval for implementation of LoSal EOR. Risks evaluated include loss of injectivity, operability of desalination facilities, and the interface with produced water management. A common learning is the need for building contingency into project design to cover all of these risks.

Organisation and resourcing have required careful consideration, and have been addressed by having a central team conduct LoSal EOR evaluations for multiple assets, in order to make the best use of scarce/critical skills.

Finally, organised and thoughtful engagement with decision-makers has been critical. Securing approval has required a careful and sustained effort, because the concept of LoSal EOR is relatively new, spans multiple disciplines, and often enhances, but does not always enable, new project economics.

Following a careful approach to risk management, LoSal waterflooding has been internally approved for two new offshore projects, key steps in building confidence for the wider application of the technology.