bluuebunny/crossref_metadata_2025 huggingface dataset:
Mechanism and Feasibility Study of Nitrogen Assisted Cyclic Steam Stimulation for Ultra-Heavy Oil Reservoir
Authors: Du Y.. , Wang Y.. , Jiang P.. , Ge J. J. , Zhang G. C.
Published: July 2013

In China, cyclic steam stimulation is the most widely applicable method for the development of common and ultra-heavy oil, and about 80% of thermal production is by CSS. Henan oilfield is one of the main producing areas of heavy oil in China and oil viscosity mainly ranges from 10000 to 30000mPa.s, belonging to ultra-heavy oil. After 6~8 cycles' huff and puff, the heating radius reaches to its economic limit and both oil and water recovery is low due to the unfavorable reservoir pressure. Though nitrogen can enhanced common heavy oil recovery after CSS, there are few reports about nitrogen assisted CSS for ultra-heavy oil. For these problems, this paper studies the feasibility and mechanism of nitrogen assisted CSS via laboratory experiments and simulation. Simulation results showed that it was feasible to inject nitrogen before CSS. Though nitrogen has little effect on the reduction of oil viscosity, the main mechanism of enhanced oil recovery was its good ability of heat insulation effect, so the heat loss of injected steam could be reduced and the heating radius was increased. Besides, compressibility coefficient of nitrogen was very large, so it could supply energy during exploitation process and avoid the rapid reservoir pressure drop. Pilot tests were conducted to several wells in Jinglou ultra-heavy oil reservoirs in Henan oilfield. Most wells achieved good effect. With the ratio of nitrogen to steam (volume ratio at standard conditions) increasing, the oil recovery got better. When the ratio was larger than 30, it had no better effect on enhanced oil recovery. These results are of significance for the development of ultra-heavy oil reservoirs.
Study of Thermal Well Test Analysis for Vertical and Horizontal Steam Injection Wells with Application to Athabasca Heavy Oil
Authors: Ghahfarokhi Ashkan Jahanban , Kleppe Jon
Published: July 2013

Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.

Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.

The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.

Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.
Enhance Heavy Oil Recovery by In-Situ Carbon Dioxide Generation and Application in China Offshore Oilfield
Authors: Jia Xiaofei , Ma Kuiqian , Liu Yingxian , Liu Bin , Zhang Jing , Li Yanlai
Published: July 2013

Miscible/Immiscible carbon dioxide injection is considered as one of the most effective technology to improve oil recovery from complicated formations. Main factor restraining wide application of this technology is its dependence on natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. However, in-situ carbon dioxide generation technology is eliminating CO2 negative impact and strong control of the process.

The EOR mechanism of proposal technology is described as follows: acid and exothermic chemical reaction function relieve deep reservoir damage, micronucleus systems formed possess abnormal reological properties allowing to improve water flooding efficiency, CO2 as a super-critical fluid decreases oil viscosity and gas form CO2 reaches such place in the formation where not many solvents can enter to, foamed gas-liquid system creates additional resistance for water injected after gas-liquid system, surfactant formed decreases interfacial tension in oil-water contact, and CO2 solved in oil increases oil volume what affects on displacement of residual oil.

Lab research shows that proposed technology can decrease injection pressure of damaged core by 11.7MPa, gas generation amount and oil volume increasing rate increases with temperature and system concentration increasing, oil volume increasing rate and oil viscosity reducing rate increasing with oil viscosity increasing. Under the conditions of 60 degrees Celsius, 10MPa, 2010mPa.s, it can increase oil volume by 25%, reduce oil viscosity by 52.7%, improve recovery efficiency by 7.6%~14.2%.

Field pilot tests were conducted in seven injection wells in China Bohai offshore oilfield in 2009~2010. All the wells present significant effect of decreasing injection pressure and increasing injection rate, average decreasing pressure by 3.2MPa, average increasing injection rate of single well by 22118m3, cumulative increasing injection rate by 154827m3, cumulative increasing oil of around production wells by 29000m3. Field pilot tests shows that proposed technology can be applied in a wide range of geological conditions, and be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called hard-to-recover oil reserves.
Eco-Friendly Surfactant for EOR in High Temperature, High Salinity Carbonate Reservoir
Authors: Ghosh Bisweswar , Obasi Daniel
Published: July 2013

Factors confronting the application of surfactant flood in high temperature, high salinity carbonate reservoirs include: high concentration of divalent ions in the formation brine, the stability of the surfactant in high thermal environment, surfactant adsorption on carbonate rock fabrics and the effect of high salinity and brine mineral composition on the multiphase system, typically encountered in carbonate reservoirs. For preliminary screening purposes, thermal stability, salinity tolerance and emulsification characteristics are given importance, while the capacity to alter the wettability of the reservoir rock towards a water-wet system is desired.

Several surfactants were screened based on their abilities to address issues of high thermal environment, high salinity effects and capacity to create a water-wet environment. A series of akyl-polyglucoside (APG) surfactants were studied which are established as eco-friendly, renewable, nontoxic and bio-degradable surfactant and one of them found to be suitable for the target carbonate reservoir. An unique approach adopted during the screening process for thermal stability was the analysis of the UV-visible light absorption profile of the surfactants after subjecting them to reservoir condition for specific periods. The APG showed salinity tolerance up to 263,000 ppm at 220 oF. During phase study divalent ions are seen to have considerable impact on the nature of microemulsion (middle phase). Incremental recovery between 19-15% was observed for surfactant flood after secondary waterflood and spontaneous imbibition of aqueous phase was enhanced in the presence of surfactant solution. The recovery was correlated with microemulsion phase behavior and wettability alteration.
Modelling of Possible Impact of Reservoir Brine Salinity During CO2 Injection
Authors: Zhang Yi , Sarma Hemanta
Published: July 2013

Although more emphasis is placed on the interaction between CO2 and oil during a CO2 injection process, the interaction of CO2 with the reservoir brine, too, could be significant in terms of its impact. This study presents a modeling approach to evaluate the possible effects of brine salinity on CO2 injection in the context of both CO2 injection and low-salinity waterflood.

In the first phase of the study, the relevant correlations widely reported in the literature were applied for investigation of brine salinity effects on CO2-brine system properties for carbonate reservoir conditions at 248°F (120°C) and 3000psi (20.68MPa). The properties investigated include CO2 solubility in brine, IFT between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine. Some relevant experimental data were also incorporated in the validation of these correlations. In the second phase, a simple pore-scale model was developed to evaluate the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. Furthermore, compositional reservoir simulation using a hypothetical geological model and a real PVT model was conducted to study the brine salinity impact on oil recovery of carbonated-water injection (CWI). The following findings were noted:

Under our reservoir conditions, lowering the brine salinity could significantly enhance CO2 dissolution in brine, consequently leading to great variation of the system properties, which may make a big difference on CO2 injection performance. The CO2 diffusion-controlled modeling showed that reduction of the salinity in the water, which acted as a barrier blocking the direct contact between CO2 and oil. This could greatly promote the rate and amount of CO2 mass transfer through water barrier to the bypassed oil. Oil recovery results from simulation studies illustrated that increasing the CO2 solubility by reducing injected brine salinity during carbonated water injection could remarkably ameliorate its performance.
Investigation on Principles of Enhanced Offshore Heavy Oil Recovery by Coinjection of Steam with Flue Gas
Authors: Zhong L.. , Dong Z.. , Hou J.. , Li Y.. , Sun Y.. , Zhao L.. , Lu W.. , Qin F..
Published: July 2013

In consideration of the difficulty to setup conventional steam generator on offshore production platform, a compact steam and flue gas generator is developed to thermally stimulate offshore heavy oil reservoir, which consists of water treatment and injection unit, fuel injection unit, air injection unit, and metering and controlling unit. The temperature of steam and flue gas generated is usually 200-350°C with 13.1-28.3wt% flue gas, the injection pressure could be up to 20MPa, and steam injection rate is 80-270 m3/day. In past two years, cyclic steam-flue gas co-injection are applied to 8 offshore horizontal heavy oil wells completed thermally or non-thermally with screen pipe, and up to 3 times of oil production rate in average is observed compared to that of cold production, the peak oil production is more than 100 m3/day.

In order to optimize the steam and flue gas co-injection strategy, laboratory experiments such as rheological characteristic measurement and PVT visualization of mixture of heavy oil and flue gas, 1D micro model displacement and 3D macro sandpack model stimulation, and numerical simulation are carried out to investigate the EOR principles. It shows significant synergistic EOR effect in steam and flue gas co-injection because of the foamy oil flow, improvement in heating and sweeping efficiency and gravity assisted drainage, besides of the combined reduction in oil viscosity by heating and gas solution. Flue gas plays an important role in co-stimulation of heavy oil with lower viscosity (500-2000mPa•s under reservoir condition) for the foamy oil flow and enlargement of heating and sweeping efficiency, at the same time, steam heating becomes more important for heavy oil with larger viscosity. At last, based on above researching results an empirical formula is developed to optimize ratio of flue gas to steam according to special reservoir conditions.
Fluid Saturation Monitoring by Cased Hole Logging for CO2 Huff-n-Puff Test in a Vietnam Offshore Field
Authors: Konishi Yusaku , Takagi Sunao , Farag Sherif , Ha Vo Viet , Hatakeyama Atsushi , Trung Phan Ngoc , Son Le Ngoc
Published: July 2013

The application of the Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) to an offshore oilfield in Vietnam has been investigated through an international joint study between Japan and Vietnam since 2007. In order to reduce and mitigate uncertainties and risks for future field scale application, a CO2-EOR pilot test was conducted in the Rang Dong field, offshore Vietnam in 2011.

The pilot test was conducted as a single-well "Huff-n-Puff" operation which was designed to minimize the test duration, required CO2 volume to observe the meaningful CO2-EOR effects and to reduce the risk of corrosion to the existing facility. Over 100 tons of CO2 were successfully injected into the Lower Miocene sandstone reservoir and the well was flowed back after two days of soaking time. Various parameters were monitored including production rate, bottom-hole pressure and production fluid properties. To investigate the CO2-EOR effects and for the purpose of monitoring the reservoir fluid saturation change, cased hole pulsed neutron saturation logging was carried out during every stage of the test. These logging operations and their timing were carefully designed to avoid any possibility of fluid contamination and to minimize operation time.

Through the analysis of the acquired logs, vertical contrast of preferential CO2 injection, zonal oil saturation change, oil saturation change with time within single run, etc., were clearly identified. These observations played important roles in evaluating the CO2-EOR effect in detail by comparing them with the reservoir simulation prediction.

In this paper the detailed design for the reservoir fluid saturation monitoring, observed results and three-phase fluid saturation changes with time are discussed.
Secondary Polymer Flooding in Extra-Heavy Oil: Gaining Information on Polymer-Oil Relative Permeabilities
Authors: Fabbri C.. , Romero C.. , Aubertin F.. , Nguyen M.. , Hourcq S.. , Hamon G..
Published: July 2013

In this work we present the results obtained from a coreflood experiment with polymer injection in secondary mode for extra heavy oil at 5500 cP viscosity. The work was carried out on a 30 cm length reconstituted core composed from cleaned reservoir sand. The core was packed using an in-house developed method, and then saturated with live oil partially degassed in PVT cell from initial reservoir conditions down to expected pressure at start of a field test (Pres). Saturation profiles were accurately measured by means of X-Ray scans on the core, enabling the visualization of flow instability development (viscous fingering). Effluents were collected in carbon cells under reservoir conditions with X-Ray production level measurements. The effluents were then flashed to atmospheric conditions, collected in test tubes and re-measured by X-Ray and UV measurements.

The polymer flood carried out in secondary mode showed excellent results with a recovery of around 60% after 1.8 PV of polymer injected at 1 cc/h, even though viscosity ratio was highly unfavourable. The estimated apparent viscosity of the polymer was 60 cP at 7 s−1, corresponding to the frontal advancement rate achieved during the coreflood. This recovery is in the same order as that obtained in tertiary mode after water flood in outcrop cores (Wassmuth et al. 2009, Wassmuth et al. 2007).
Kinetics of the Low Salinity Waterflooding Effect Studied in a Model System
Authors: Mahani H.. , Berg S.. , Ilic D.. , Bartels W. -B. , Joekar-Niasar V..
Published: July 2013

Low salinity waterflooding (LSF) provides an opportunity for improved oil recovery. However the complexity of the process makes both the fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore we use a model system for sandstone which consists of clay minerals deposited on a glass substrate and covered with crude oil droplets in order to study the kinetics of oil detachment when exposed to low salinity brine. The system is equilibrated first under high saline brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution allowing for a detailed analysis of the contact angle and the contact area as a function of time.

We observe that the contact angle and contact area of oil with the substrate reach a stable equilibrium at high saline brine and show a clear response to the low salinity brine towards less oil wetting conditions and ultimately detachment from the clay (Na-montmorillonite) substrate. This behavior is characterized by the motion of the 3-phase (oil-water-solid) contact line which is initially pinned by clay particles at high salinity conditions and that pinning decreases upon exposure to low salinity brine leading to a decrease in contact area and contact angle which indicates wettability alteration towards a more water-wet state. When the contact angle reaches a critical value around 40-50°, oil drops start to detach from the clay. During detachment most of the oil is released but in some cases a small amount of oil residue is left behind on the clay substrate.

Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy over adhesion force balance and has a time constant of hours to days; i.e., it takes longer than commonly assumed.

The unexpectedly long time constant, i.e. longer than expected by diffusion alone, is compatible with an electrokinetic model. It is an important finding which provides new insights into the pore-scale mechanism of LSF and also has implications for the execution of low salinity coreflooding experiments, i.e. provides how long it takes to reach equilibrium and at which time scale a response to LSF can be expected.
Case Study of the Mannville B ASP Flood
Authors: McInnis Lee E , Hunter Kate D , Ellis-Toddington Tyler T , Grawbarger David J
Published: July 2013

In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.

A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.

Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.

The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
Polymer Flooding of Heavy Oil Under Adverse Mobility Conditions
Authors: Levitt David , Jouenne Stephane , Bondino Igor , Santanach-Carreras Enric , Bourrel Maurice
Published: July 2013

Polymer flooding is investigated in laboratory corefloods for potential application in a 2000 cP - 5000 cP heavy oil field. An incremental oil recovery is noted with the addition of very low concentrations of partially-hydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection.

Existing scaling groups for viscous instability are investigated. Corefloods in this study and others are found to be in or near the transition zone, where recovery may be sensitive to variables such as core diameter, while field floods are all in the &"pseudo-stable" region, where this may not be the case.

Mounting evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the fact that it is not feasible to obtain unit mobility ratio with non-thermal methods. Additional work is necessary to determine appropriate optimization methods and criteria for these floods.
Rejuvenating Viscous Oil Reservoirs by Polymer Injection: Lessons Learned in the Field
Authors: Mogollón José Luis , Lokhandwala Taher
Published: July 2013

Viscous oils have adverse mobility that causes production to decline rapidly following a period of primary recovery. Traditionally, enhanced oil recovery (EOR) for this kind of oil has mostly relied on reducing viscosity and increasing mobility using thermal methods or miscible gas injection. However, in some cases-for example, deep reservoirs, thin sands, or restricted offshore applications-these methods might not be feasible. This paper discusses published field studies using polymer flooding EOR for viscous oil and provides recommendations for its applicability.

In countries with reservoirs that present challenges for use of traditional EOR methods, such as Canada, China, and Suriname, polymer flooding has been field tested as a reliable oil-sweeping method while minimizing the risk of high water cut. With oil viscosities at reservoir conditions up to 5000 cp and reasonable economic conditions, polymer flooding has been shown to be an attractive EOR alternative. The study cases presented show that polymer concentrations need only be between 800 to 1,500 ppm to ensure successful results.

Concerns about low or poor injectivity of polymers are being overcome using fracturing and horizontal wells, while high-value, limited-space challenges on offshore platforms are being addressed through modular and minimized installations. Additionally, most conventional waterflood monitoring and surveillance techniques are also applicable to polymer floods, while polymer use in backflow tests and as a tracer has also been proposed.

This study's projection shows a 90% probability of positive net present value (NPV) under broad ranges of uncertainty for oil price, recovery factor (RF), capital expenditures (CAPEX), and operational expenditures (OPEX). The results of this paper show that polymer flooding presents a clear and feasible alternative for increasing the RF of viscous oil. To this end, a detailed study is provided of its advantages and the reservoir condition range of applicability.
Decision Making Tool to Assist in Choosing Between Polymer Flooding and Infill Well Drilling: Case Study
Authors: Alusta Gamal , Mackay Eric , Fennema Julian , Armih Khari
Published: July 2013

In previous publications, we introduced a methodology to assist in choosing between polymer flooding and infill well drilling. The method has been firstly applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process (Alusta, et. al. SPE 143300) and the method is then applied and tested with varied operational and economic parameters to investigate whether it is better to start polymer flooding earlier or later in the life of the project (Alusta et al., SPE 150454).

The method was then applied to actual field data where the choice of infill well drilling has already been made, to test the robustness of the method against a conventional decision making process for which there is historical data. Application of the method identified that polymer injection would indeed be economically unfavourable (Alusta et al., SPE 163298).

The approach is then carried out in a field where the choice has yet to be made, a field which is currently under waterflood management, and where the operator is considering polymer flooding as an alternative (or in addition) to infill well drilling. Application of the method has identified that under certain technical conditions (related to polymer concentration and duration of polymer injection) and certain economic conditions (related to oil price and operating costs) polymer flooding entails a significant risk of failure, but that if appropriate technical choices are made, and under prevailing economic conditions, polymer flooding is very beneficial for this field, and a combination of polymer flooding and infill well drilling is optimal.

We consider that this approach will be very useful to the industry in helping to make the appropriate choice between potentially various EOR techniques and infill well drilling, taking full account of reservoir engineering AND economic considerations TOGETHER.
Mechanistic Study on the Influence of Water Alternating Miscible CO2 Flooding of Chalk Reservoirs on Oil Recovery and Ionic Interaction with Asphaltene
Authors: Hamouda Aly A.
Published: July 2013

CO2 is injected into mature reservoirs for both sequestration and EOR. The effect of CO2 flooding on asphaltene stability has been extensively addressed in literature. In contrast, asphaltene / water interaction has not received much attention in literature.

The objective of the paper is to address the asphaltenic oil recovery by water alternating CO2 injection (WACO2) and asphaltene/ions interaction. Different water compositions, such as synthetic seawater (SSW) and low salinity water (LSW), Na2SO4, MgCl2 ions, and ion free water (DW), are used. SO4-2 and Mg+2 ions were selected based on previous work on their interaction with chalk minerals and modifying the surfaces to more water wet. CO2 is injected in miscible mode within the WACO2 recovery process. For simplicity outcrop cores and model oil were used. Model oil consists of n-C10, 0.35wt% asphaltene (extracted from a Middle East crude oil) and natural surfactant (stearic acid, SA). The effects of water injection rates were also investigatd to address the oil recovery efficiency in the cores and assess the water/oil/rock interaction as a function of injection rates. Imbibition process with various water compositions was tested for cores unflooded and flooded with CO2. This is to address the effect of CO2 on the fluids interaction.

It was shown that higher oil recovery was obtained when Mg+2 solution was used as imbibing fluid after CO2 flooding compared to SO4-2 solution. The opposite was observed without the CO2 flooding where higher recovery was obtained when Na2SO4 solution was used as an imbibing solution compared to that with MgCl2 as imbibing fluid.
Innovative Field-Scale Application of Injecting Condensate Gas and Recycling Gas into Medium Oil Pool: Case Study in Sudan
Authors: Tang Xueqing , Wang Ruifeng , Zhang Hui
Published: July 2013

This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.

Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.

Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.

Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Using Chromatographic Fingerprint Technique to Monitor Individual Zone Production in ASP Flooding
Authors: Liu Xincang , Zhang Dong , Ding Jian , Ran Fajiang , Zhao Mingchuan , Li Shiyong
Published: July 2013

It's very important to evaluate layered producing performances at different stages in the course of oilfield development, but due to limitations of monitoring well conditions and logging expenses, it is difficult to comprehensively and systematicly monitor all the producers, and this will bring troubles to adjustments and evaluations during oil field development. To solve this problem, the Chromatographic Fingerprint technique is introduced to monitor layered producing performances in test area F which has four target zones in Daqing Oilfied. After response of alkaline-surfactant-polymer (ASP) flooding, screw pumps are adopted to some producers to minimize scaling in F area where producing profile surveys for annulus wells aren't adaptable to mornitor the layed producing status. Pre-test in lab shows that the Chromatographic Fingerprint technique is feasible for the four individual test zones for there are distinct chromatographic fingerprint differences, and ASP injected solution has less influences on fingerprints. A fuzzy interpretation template has been successfully set up for commingled 4-6 layers production numerical simulation by using EPB neural network model, and relative errors can be controlled below 10%. The technique has been applied to the producers for 180 times. In-situ test results are stable and correspond to the static information of lays. It indicates that the Chromatographic Fingerprint technique is suitable for monitoring individual zone producing performances of ASP flooding. The results from the fuzzy interpretation template have provided powerful data to re-recognize the connectivity of heterogeneous reservoir between injectors and producers. It can be applied to producers whose producing intervals belong to the fuzzy interpretation template. The oil production proportion of per lay's can be easily achieved after the sample from the well fluid is analysed with chromatography and calculated with the fuzzy interpretation template. The technique has proved to be economical and it is not astricted by well conditions, so it can play an important role to guide development programs' adjustments and evaluations in oilfields.
Monitoring Water Alternate Gas (WAG) Process Using Streaming Potential Measurement
Authors: Anuar S. M. , Jaafar M. Z. , Sulaiman W. R. , Ismail A. R.
Published: July 2013

Spontaneous potential (SP) is commonly measured during reservoir characterization. SP signals are also generated during hydrocarbon production due to the streaming potential occurrence. Measurement of SP could be used to detect and monitor water encroaching on a well. SP signals could also be monitored during production, with pressure support provided by water alternate gas (WAG) process. The objectives of this study are to quantify the magnitude of the SP signal during production by WAG injection and to investigate the possibility of using SP measurements to monitor the sweep efficiency.

Measurement of streaming potential has been previously proposed to detect the water encroachment towards a production well. The peak of the signal corresponds to the waterfront where there is a change of saturation from ionic water to non-polar hydrocarbon. Similar trend is predicted in the case of WAG where we have several interfaces between the injected water and the injected gas.

The results indicate that the magnitude of the SP generated in hydrocarbon reservoir during WAG process can be large and peaks at the location of the moving water front. Gas, which can be assumed to be non-polar, exhibit no electrokinetic effect.  These observations suggest that WAG displacement process can be monitored indirectly from the signal acquired. Water or gas override can be detected and controlled if wells were equipped with inflow-control valves. As a conclusion, the SP measurement is a promising method to monitor the effectiveness of a WAG process.

This study is significant because monitoring the progress of water and gas in a WAG process is key in the effectiveness of this enhanced oil recovery method. Measurement of the streaming potential provides another method besides using tracers to monitor the WAG profile. Better monitoring will lead to more efficient displacement and great benefits in term of economy and environment.
A Discussion of Different Approaches for Managing the Timing of EOR Projects
Authors: Sayavedra Leo , Mogollon Jose Luis , Boothe Mike , Lokhandwala Taher , Hull Rob
Published: July 2013

Studies indicate that as much as 60% of the initial oil-in-place may remain after secondary recovery. At the same time, Enhanced Oil Recovery (EOR) methods are growing more cost effective, with 3% of current worldwide production now attributable to EOR.

EOR projects, however, are strongly influenced by economics and long-run crude oil prices. In addition, EOR investment decisions are also heavily impacted by the timing of the switch from primary recovery to water flooding, and then later, the timing of the switch from water flooding to tertiary oil recovery. The question is what are the key approaches and decision parameters that drive the timing of these decisions? Do you design for EOR up front during concept development planning or do you wait and address EOR as a field matures?

This paper will discuss the trade-offs between adopting two distinctly different approaches for making EOR switching decisions, designing EOR up front vs. implementation as the field matures. One approach embraces proactively designing for and executing EOR during the initial development of a field. The other approach bases switching decisions on the conditional indicators of the reservoir, coupled with a view toward the long-run oil price. This paper will also explore the key decision parameters that impact the choice of which EOR approach to pursue.
Injection and Production Profile Modification for Enhanced Oil Recovery: Mechanical or Chemical Methods?
Authors: Kim Amos S. , Thornton Kim V. , Boothe Michael L.
Published: July 2013

Enhanced oil recovery (EOR) is fundamental to increasing the ultimate recovery of a reservoir. Among several parameters that govern the success of an EOR project, profile modification is a key factor when flooding heterogeneous reservoirs with multiple zones. Given the time and economic constraints, simultaneous flooding of all zones of interest is preferred although it can be difficult for reasons such as a varying pressure and fluid injectivity/productivity profile caused by permeability contrasts between zones. Injection fluids can bypass low-permeability oil-saturated zones, not achieving the full benefit of injection if the profile is not properly modified. Failure to modify production profiles can lead to early water and gas breakthrough. To mitigate these problems, various approaches such as mechanical downhole equipment or chemical treatments have been used.

This paper presents a comparison of the use of mechanical versus chemical conformance control systems in different scenarios. Conformance control is defined as the process that helps improve the drive mechanism for better sweep of reservoir. The basic premises of both mechanical and chemical systems are introduced. Their applicability, operational benefits, and disadvantages are also described. A 3D reservoir simulator is used to illustrate the varying sweep efficiencies, depending on the conformance control method used. The result from the best case with both injector and producer profile modification demonstrated nearly double the oil recovery compared to the base case with no treatment.
Applicability of Hydroxyethylcellulose Polymers for Chemical EOR
Authors: Abbas Sayeed , Sanders Aaron W. , Donovan James C.
Published: July 2013

Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
Monitoring Foam Stability in Foam Assisted Water Alternate Gas (FAWAG) Processes Using Electrokinetic Signals
Authors: Omar S.. , Jaafar M. Z. , Ismail A. R. , Sulaiman W. R.
Published: July 2013

The natural pressure in hydrocarbon reservoirs is only sufficient in producing small amount of hydrocarbon at the end of the depletion stage. Therefore, in order to enhance or increase the hydrocarbon recovery, water or other fluids are injected into the formation to extract the hydrocarbon from the pore space. This common practice is known as Improved or Enhanced Oil Recovery (IOR or EOR). Foam is purposely used in some of the EOR displacement processes in order to control the mobility ratio, hence improving the volumetric sweep efficiency.

The efficiency of a foam displacement process in EOR depends largely on the stability of the foam films. In laboratory, foam stability is usually measured through physical observation of the foam bubble in a glass tube. Unfortunately, this direct observation is not possible in the reservoir. Therefore, indirect measurement such as the measurement of electrokinetic signal would be a better alternative. This study aims to determine the correlation between the foam stability and the associated streaming potential signals which resulted from the flowing fluid in foam assisted water alternate gas (FAWAG) process.

The experimental work will be conducted at the Reservoir and Drilling Engineering Laboratories at the Faculty of Petroleum and Renewable Energy Engineering (FPREE), UTM. The investigation includes sample preparation, sample analysis, displacing fluid formation, rheological properties test and electrokinetic signal measurement by using NI Data Acquisition System (NIDAS). It is expected that the burst of the foam bubble will change the pattern of the electrokinetic signals.

The research findings could lead to a new approach in monitoring a FAWAG process. Application in the real field could benefit the oil and gas industry in term of making the EOR process more efficient and more economic.
Peptide Mimetic of the S100A4 Protein Modulates Peripheral Nerve Regeneration and Attenuates the Progression of Neuropathy in Myelin Protein P0 Null Mice
Authors: Moldovan Mihai , Pinchenko Volodymyr , Dmytriyeva Oksana , Pankratova Stanislava , Fugleholm Kåre , Klingelhofer Jorg , Bock Elisabeth , Berezin Vladimir , Krarup Christian , Kiryushko Darya
Published: July 2013

We recently found that S100A4, a member of the multifunctional S100 protein family, protects neurons in the injured brain and identified two sequence motifs in S100A4 mediating its neurotrophic effect. Synthetic peptides encompassing these motifs stimulated neuritogenesis and survival in vitro and mimicked the S100A4-induced neuroprotection in brain trauma. Here, we investigated a possible function of S100A4 and its mimetics in the pathologies of the peripheral nervous system (PNS). We found that S100A4 was expressed in the injured PNS and that its peptide mimetic (H3) affected the regeneration and survival of myelinated axons. H3 accelerated electrophysiological, behavioral and morphological recovery after sciatic nerve crush while transiently delaying regeneration after sciatic nerve transection and repair. On the basis of the finding that both S100A4 and H3 increased neurite branching in vitro, these effects were attributed to the modulatory effect of H3 on initial axonal sprouting. In contrast to the modest effect of H3 on the time course of regeneration, H3 had a long-term neuroprotective effect in the myelin protein P0 nul mice, a model of dysmyelinating neuropathy (Charcot-Marie-Tooth type 1 disease), where the peptide attenuated the deterioration of nerve conduction, demyelination and axonal loss. From these results, S100A4 mimetics emerge as a possible means to enhance axonal sprouting and survival, especially in the context of demyelinating neuropathies with secondary axonal loss, such as Charcot-Marie-Tooth type 1 disease. Moreover, our data suggest that S100A4 is a neuroprotectant in PNS and that other S10C proteins, sharing high homology in the H3 motif, may have important functions in PNS pathologies.
Signaling of High Mobility Group Box 1 (HMGB1) through Toll-like Receptor 4 in Macrophages Requires CD14
Authors: Kim Sodam , Kim Sun Young , Pribis John P. , Lotze Michael , Mollen Kevin P. , Shapiro Richard , Loughran Patricia , Scott Melanie J. , Billiar Timothy R.
Published: July 2013

High mobility group box 1 (HMGB1) is a DNA-binding protein that possesses cytokinelike, proinflammatory properties when released extracellularly in the C23–C45 disulfide form. HMGB1 also plays a key role as a mediator of acute and chronic inflammation in models of sterile injury. Although HMGB1 interacts with multiple pattern recognition receptors (PRRs), many of its effects in injury models occur through an interaction with toll-like receptor 4 (TLR4). HMGB1 interacts directly with the TLR4/myeloid differentiation protein 2 (MD2) complex, although the nature of this interaction remains unclear. We demonstrate that optimal HMGB1-dependent TLR4 activation in vitro requires the coreceptor CD14. TLR4 and MD2 are recruited into CD14-containing lipid rafts of RAW264.7 macrophages after stimulation with HMGB1, and TLR4 interacts closely with the lipid raft protein GM1. Furthermore, we show that HMGB1 stimulates tumor necrosis factor (TNF)-α release in WT but not in TLR4−/−, CD14−/−, TIR domain-containing adapter-inducing interferon-β (TRIF)−/− or myeloid differentiation primary response protein 88 (MyD88)−/− macrophages. HMGB1 induces the release of monocyte chemotactic protein 1 (MCP-1), interferon gamma-induced protein 10 (IP-10) and macrophage inflammatory protein 1α (MIP-1α) in a TLR4- and CD14-dependent manner. Thus, efficient recognition of HMGB1 by the TLR4/MD2 complex requires CD14.
Effect of Recombinant α1-Antitrypsin Fc-Fused (AAT-Fc) Protein on the Inhibition of Inflammatory Cytokine Production and Streptozotocin-Induced Diabetes
Authors: Lee Siyoung , Lee Youngmin , Hong Kwangwon , Hong Jaewoo , Bae Suyoung , Choi Jida , Jhun Hyunjhung , Kwak Areum , Kim Eunsom , Jo Seunghyun , Dinarello Charles A. , Kim Soohyun
Published: July 2013

α1-Antitrypsin (AAT) is a member of the serine proteinase inhibitor family that impedes the enzymatic activity of serine proteinases, including human neutrophil elastase, cathepsin G and neutrophil proteinase 3. Here, we expressed recombinant AAT by fusing the intactAATgene to the constant region of IgG1 to generate soluble recombinant AAT-Fc protein. The recombinant AAT-Fc protein was produced in Chinese hamster ovary (CHO) cells and purified using mini-protein A affinity chromatography. Recombinant AAT-Fc protein was tested for antiinflammatory function and AAT-Fc sufficiently suppressed tumor necrosis factor (TNF)-α-induced interleukin (IL)-6 in human peripheral blood mononuclear cells (PBMCs) and inhibited cytokine-induced TNFα by different cytokines in mouse macrophage Raw 264.7 cells. However, AAT-Fc failed to suppress lipopolysaccharide-induced cytokine production in both PBMCs and macrophages. In addition, our data showed that AAT-Fc blocks the development of hyperglycemia in a streptozotocin-induced mouse model of diabetes. Interestingly, we also found that plasma-derived AAT specifically inhibited the enzymatic activity of elastase but that AAT-Fc had no inhibitory effect on elastase activity.
In Vivo Regulation of the μ Opioid Receptor: Role of the Endogenous Opioid Agents
Authors: Gonzalez-Nunez Veronica , González Ada Jimenez , Barreto-Valer Katherine , Rodríguez Raquel E.
Published: July 2013

It is well known that genotypic differences can account for the subject-specific responses to opiate administration. In this regard, the basal activity of the endogenous system (either at the receptor or ligand level) can modulate the effects of exogenous agonists as morphine and vice versa. The µ opioid receptor from zebrafish, dre-oprm1, binds endogenous peptides and morphine with similar affinities. Morphine administration during development altered the expression of the endogenous opioid propeptides proenkephalins and proopiomelanocortin. Treatment with opioid peptides (Met-enkephalin (Met-ENK), Met-enkephalin-Gly-Tyr (MEGY) and β-endorphin (β-END)) modulated dre-oprm1 expression during development. Knocking down the dre-oprm1 gene significantly modified the mRNA expression of the penk and pomc genes, thus indicating that oprm1 is involved in shaping penk and pomc expression. In addition, the absence of a functional oprm1 clearly disrupted the embryonic development, since proliferation was disorganized in the central nervous system of oprm1-morphant embryos: mitotic cells were found widespread through the optic tectum and were not restricted to the proliferative areas of the mid- and hindbrain. Transferase-mediated dUTP nick-end labeling (TUNEL) staining revealed that the number of apoptotic cells in the central nervous system (CNS) of morphants was clearly increased at 24-h postfertilization. These findings clarify the role of the endogenous opioid system in CNS development. Our results will also help unravel the complex feedback loops that modulate opioid activity and that may be involved in establishing a coordinated expression of both receptors and endogenous ligands. Further knowledge of the complex interactions between the opioid system and analgesic drugs will provide insights that may be relevant for analgesic therapy.