bluuebunny/crossref_metadata_2025 huggingface dataset:
Pore Scale Modeling of Gravity Drainage Dominated Flow under Isothermal and Non-Isothermal Conditions
Authors: Argüelles F. J. , Babadagli T.
Published: April 2012

Immiscible or miscible gas injection and steam assisted gravity drainage are well known examples of gravity dominated recovery processes under isothermal and non-isothermal conditions, respectively. It is commonly observed in these processes that field scale applications yield less recovery than estimated. In order to clarify the reasons associated with the amount of the remaining oil in these processes, especially for the non-isothermal ones such as steam assisted gravity drainage (SAGD), pore scale experimental analysis of the mechanics is needed. In this paper, as complementary to our previous work (Argüelles and Babadagli, 2011) that used horizontally positioned circular capillaries, we studied the gravity drainage dominated flow of heavy-oil at pore scale using vertically positioned square and circular capillary tubes. Heavy crude oil samples were used and an elementary volume in the swept zone of SAGD was simulated using a single capillary tube. Detailed experiments were carried out to analyze: (1) the effects of oil viscosity on non-isothermal gravity drainage (including free fall), (2) behavior of co-current gravity driven displacement, (3) interplay among capillary, gravity and viscous (injection rates) forces and wettability, and (4) residual oil saturation and phase distribution in the capillaries. Also, we compared the residual oil saturation development results obtained for square capillaries with those for the circular ones having a diameter approximately equal to the side of the square capillary tube.
Novel Barium Sulfate Scale Inhibitor for Use in High Iron Environments
Authors: Dickinson W. , Sanders L.
Published: April 2012

Iron is known to affect the performance of polymeric and phosphonic acid based inhibitors used to control barium sulfate scale during oil and gas production. To evaluate these effects, the performances of both types of inhibitors have been determined in the presence of iron in simulated oilfield brine. Iron adversely affected the performance of the polymer but enhanced the performance of the phosphonate inhibitor. Evaluation of blends of the two inhibitors showed improved performance compared to either type of inhibitor used separately. An optimum ratio of polymer to phosphonate was determined which achieved greater than 90% inhibition of barium sulfate formation over the range 0 – 120 ppm iron.
The Way Forward for Deepwater and Ultra Deepwater Drilling in Trinidad and Tobago
Authors: Rajnauth J
Published: April 2012

Future deepwater drilling in Trinidad and Tobago will definitely present enormous challenges. During the period 1999 to 2003, eight deepwater wells were drilled in deepwater acreage. None of these wells found hydrocarbon in economic quantities although abundant reserves have been found in the shelf area (< 1000 meters water depth).

The data from these wells would be useful for further deepwater and ultra deepwater drilling in Trinidad. To date, no wells have been drilled in our ultra deepwater acreage but seismic acquisition and processing has been undertaken. Thus lessons learned from the first deepwater campaign will definitely propel the way forward for further exploration works in deeper waters. We have to adapt our operations to accommodate the problems associated with our first phase of deepwater drilling in our area. This paper will look at the approaches we should adapt in the next phase of deepwater drilling. Some of these issues include rig selection, well location, well design and planning, environmental studies (wind, wave, climate etc.) and shallow hazard assessment. The key learnings from previous deepwater drilling events are useful in future operation in Trinidad and Tobago.
Borehole Geometry Estimation through Real Time Measurement of Cavings Flow while Drilling
Authors: Carvajal J. M. , Salcedo A. Lache , Mateus D. C. , Caceres E.
Published: April 2012

Measuring cuttings and cavings flow while drilling allows to account the amount of cuttings which are drive out from the annular section of the hole, quantify the volume of collapse in the wellbore and estimate the final well geometry at real time conditions, these information can be used to develop strategies that may help to control wellbore stability while drilling.

The design, construction and a field testing of a prototype that can automatically record data while drilling from cavings and cuttings flow to be analyzed in real time is presented in this paper, the prototype is used to identify situations in which cuttings and cavings flows are high enough to cause instability of the drilled well in real time. The system was developed to estimate the actual diameter of the well based on information gathered by it, this can be used to establish a comparison between the ideal diameter and the calculated which will allow identifying zones in which the wellbore failure may occur and figured the approximate size of collapse.

This prototype has been used in several wells in Colombia, located at different basins of the country, a study case of a well sited at Middle Magdalena River Valley Basin is presented in this article, the results obtained from the use of this tool are satisfactory and can accelerate the process of decision making and evaluation of the borehole stability while drilling since the responses are given in real time.
Stable Emulsion and Demulsification in Chemical EOR Flooding: Challenges and Best Practices
Authors: Nguyen Duy , Sadeghi Nicholas
Published: April 2012

In this paper, factors such as key issues (e.g. emulsions), challenges (e.g. water treatment), and best practices (e.g. combination of equipment design and demulsifier to treat emulsions) associated with chemical enhanced oil recovery (CEOR) are presented. During the application of chemical EOR floods, breakthrough of the injection chemicals such as surfactant and polymer or polymer alone periodically occurs resulting in stable emulsions. This paper was compiled from the literature to report the effects of alkali, polymers, surfactants, asphaltenes, resins, and shear rates on emulsion stability. When treated with polymer alone, the produced fluid was not very stable and resolved into two phases: oil and water. However, the water exhibited a high oily content and was difficult to treat due to the adsorption of polymer onto the surface of the oil droplets. Zeta potential measurements indicated that oil droplets were not only stabilized by steric stabilization of the polymer but also by electrostatic stabilization. The effect of polymer on emulsion stability in SP (surfactant and polymer) or ASP (alkali, surfactant, and polymer) floodings is complicated. Polymer can form a "bridge" between two oil droplets and decrease the emulsion stability; however, polymer can also enhance the emulsion stability via electrostatic and steric stabilization. Asphaltenes and resins present in the crude oil form a rigid film around water droplets, contributing to high BS&W values. Surfactants and alkali decrease the interfacial tension and zeta potential, contributing to the stability of oil droplets. As concentrations of the injection chemicals in the produced fluid varied, the stability of the emulsion also changed. As a result, the selected demulsifier has to be robust. In this paper, water soluble demulsifiers and oil soluble demulsifiers were used to treat the emulsion. The demulsifier greatly lowered water content in the oil phase (BS&W<0.5%) and oil concentration in the water phase (less than 50 ppm). The demulsification mechanism was also investigated in terms of elastic modulus, particle size, and interfacial tension. Application of this novel demulsifier resulted in a much more effective oil/water separations process with the production of dry oil and clean water at a pilot ASP flood that was experiencing very stable emulsions.
World's First Combination Of Acid & Steam Provides A New Dimension To Heavy Oil Enhanced Recovery Process
Authors: Shaheen Tarek , Hassan Wael , Siddiqqi Irfan , Kamal Salah
Published: April 2012

The Issaran field located 200 km east of Cairo-Egypt, is a heavy oil reservoir. The oil is of 8-12 degree API with viscosity of 4000 cps at standard conditions.

Productivity of the wells has sharply declined due to increase in the water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits.

The major challenge to remedy this situation was; 1) The creation of new extended flow channels. 2) Accurate placement of the treatment. 3) Diversion within the reservoir. 4) Provide sustain production increase. And 5) The flow and the production of oil through the newly formed wormholes.

A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with fit for purpose chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation.

The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for enhanced recovery process in the heavy oil reservoirs.
Potential For Inhibitor Squeeze Application For Silicate Scale Control In ASP Flood
Authors: Sonne Jennifer , Miner Kirk , Kerr Scot
Published: April 2012

Alkaline surfactant polymer (ASP) floods often induce silicate scaling. Scaling of the production tubing, rod pumps and other surface equipment causes frequent workovers, resulting in increased costs and non-productive time. High treatment rates and short run times drove the re-evaluation of the problem in pursuit of more targeted products and applications. The formation of silicate scale is complicated by its dependence on multiple water chemistry-dependent factors which vary as the flood progresses (Gill 1998). These factors affect silicate scaling tendency, and consequently, severity of the problem. A range of silicate scale inhibitors has been developed to mitigate problems in oilfields afflicted with silicate scaling due to ASP flooding (Qing et al. 2002). A new test method using an optical scanning device was developed to better characterize inhibition and dispersant qualities of inhibitors on silicate scale in solution under static conditions. The advantage of this method is more comprehensive data generated by multiple-point measurements. Scaling reactions are more easily modified and differentiated. Water chemistries from several wells in an ASP-flooded field in Southern Alberta with known silicate scaling issues defined the tested synthetic brine. By allowing the mixed synthetic brine to react before adding inhibitor, the effect of delayed chemical injection may be studied. Performance of the tested inhibitor was significantly reduced by slight injection delay and may account for the discrepancy often seen between laboratory performance data and failures observed in the field. It is proposed that the performance of silicate scale inhibitors may be improved when applied by squeeze, where the inhibitor can inhibit silica polymerization within the formation and may provide substantial improvement over conventional continuous down-hole injection. Test work done to confirm the feasibility of the squeeze included fluid compatibility and core damage studies. These performance tests demonstrated the treating advantages of a scale inhibitor squeeze.
Water Injection Subsurface Challenges and Reactive Transport Modelling
Authors: Al Mayahi Najma , Snippe Jeroen , Rucci Facundo , Linthorst Steef
Published: April 2012

Two main development options were identified for a carbonate stringer reservoir being waterflood and Miscible Gas Injection (MGI). The waterflood project economics were more favourable; however potential showstoppers were identified. The key risks associated with waterflooding this reservoir are halite precipitation, anhydrite swelling, injectivity loss and the quality of produced water.

Faced with this challenge the study team started dedicated studies on rock integrity, water compatibility and scaling mitigation in order to assess and moderate these risks. Reactive Transport Modelling (RTM) work was initiated. The Reactive Transport Model is a reservoir simulator coupled with geochemical simulation. The objective of the model is to quantify reactions between rock and fluid, and forecast pH and salinity over time at the producer. This is dependent on data obtained from core flood experiments, and H2S and CO2 solubility data obtained from literature review and thermodynamic modelling. In order to calibrate the models the following studies and experiments were initiated:Literature reviews (i.e analogues for waterflooding in sour fields, anhydrite swelling, and H2S (and CO2) solubility in brine);Core flood experiments for temperature and salinity range and halite dissolution with the objective to get dissolution rates as a function of surface area, temperature and salinity;In addition a field injectivity trial was executed to proof injectivity and calibrate the models

Significant work has been done on the subsurface risks associated with waterflooding. This integrated and dedicated study has contributed at large to the project’s key decisions. A key conclusion from the study was that anhydrite to gypsum conversion is unlikely to pose a risk to well integrity or injectivity hence there is no need to heat the injected water. This resulted in a saving of $160 mln on operating costs. For halite scaling, the formation water bank poses a higher risk than mineral (halite) dissolution in the reservoir. Hence jet pumping was selected as a lifting mechanism providing also flow assurance.
Developing a Layered Heterogeneous Precambrian Reservoir by Polymer Flooding
Authors: Abu-Shiekah Issa , Nieuwenhuijs Robbert A , Ross Ryan , Lanier Gary , Belushi Abdulaziz , Saadi Faisal , Nofli Sami , Harthi Said , Van Wunnik John
Published: April 2012

Enhanced oil recovery through injection of a solution of water and polymer is becoming a mature chemical flooding technique. In general, reservoirs with mature water-flooding projects offer an excellent opportunity for extension with polymer injection as uncertainties associated with reservoir connectivity and injection potential are already substantially reduced. For our particular reservoir an additional fortunate circumstance includes an ongoing polymer injection project in an adjacent reservoir which enables easy field testing given the local operational challenges and circumstances.

This paper presents ongoing work related to improving ultimate oil recovery from an active water flood project by polymer injection where a polymer flooding pilot is already ongoing. The work includes studies to extend the existing polymer injection facilities of a nearby polymer project to this rather different, in geologic terms, Precambrian reservoir with much lower permeability, oil saturations and significantly more layered reservoir architecture. Geological and petrophysical workflows together with dynamic modeling history matching iterations resulted in reducing subsurface uncertainties such as the distribution of permeability and initial oil saturation. Reservoir compartment connectivity and sweep efficiency are constrained by matching pressure and injection, as well as, production data from 180 wells. Polymer injection feasibility is proven through: dynamic modeling, laboratory experiments, ongoing polymer injection pilot and adapting learning’s from the ongoing adjacent polymer project. The study reveals that a polymer injection project is economically feasible under a range of subsurface and costs scenarios.
Water-Based Enhanced Oil Recovery EOR by "Smart Water" in Carbonate Reservoirs
Authors: Fathi S. Jafar , Austad Tor , Strand Skule
Published: April 2012

Water chemistry has a profound effect on the stability of the water film and desorption of organic oil components from the mineral surfaces in a water—based enhanced oil recovery (EOR) process. By knowing the chemical mechanism for the symbiotic interaction between the active ions in seawater; Ca2+, Mg2+, and SO42—, "Smart Water" can be designed and optimized in terms of salinity and ionic composition as an EOR—fluid. In the present study, the efficiency of "Smart Water" on oil recovery in carbonate rock is summarized and discussed in the temperature range of 70—120 °C. By removing non–active salt, NaCl, from the composition of the injected seawater, the oil recovery by spontaneous imbibition was improved by about 5–10% of OOIP compared to seawater. On the other hand, an increase in the concentration of NaCl in the imbibing fluid resulted in reduced oil recovery of 5% of OOIP. A systematic decrease in oil recovery was observed when diluting seawater with distilled water to obtain a low salinity brine, 1000–2000 ppm. The decrease in the oil recovery was attributed to the reduced concentration of the active ions. When seawater depleted in NaCl was spiked by SO42–, the oil recovery increased by about 5 to 18% of OOIP compared to seawater depleted in NaCl. The amount of Ca2+ in the seawater depleted in NaCl had no significant effect on the oil recovery at low temperatures, ≤100 °C, but improvements were observed at higher temperatures. The wetting condition after spontaneous imbibition of seawater, seawater depleted in NaCl, and seawater depleted in NaCl spiked with sulfate was monitored using a chromatographic wettability test, and it showed an increasing order in the water–wet fraction, in line with increased oil recovery. The results were discussed in terms of the previously suggested mechanism and the effect of the ionic double layer at the rock–brine interface.
Heavy Oil Secondary Production Optimization - Successful Application of New Horizontal Well Drilling Pattern Strategy and Fit for Purpose Technology in Nearly Obsolete Mature Heavy Oil Reservoir in North East China
Authors: Xiang Ren Fang , Yan Sun , Zhong Yu Tian , Zhao Fan Hong , Yun Lv Jian , Halomoan Parlindungan Monris , Bin Yang , Hui Xu Chong , Xie Roc Xiaopeng , Ruo Wang
Published: April 2012

XH27 is a heavy oil reservoir with a high oil/water viscosity ratio that incurs bottom water coning effects. To enhance the primary heavy oil production, 59 vertical wells with a 141-m square well pattern have been drilled since 1992. The highest primary oil production of 360 tons/day was reached in 1994. Starting in 1996, the reservoir fell into a significant production decline phase. The reservoir was on the brink of obsolescence in 2006 when a 93.6% water-cut discharge and a 0.26% annual oil recovery factor were recorded.

Based on detailed static reservoir characterization and updating of the dynamic reservoir model, the square vertical well pattern development strategy was shifted to a horizontal well drilling venture with a net-remaining-oil-distribution pattern. The major shortcoming to overcome was accurate placement of the horizontal section trajectory close to the reservoir top for the injector-producer wells. The thin oil-column target of less than 5 m added to the challenge.

To overcome these challenges, real-time well placement monitoring using high-resolution resistivity images, along with near-bit measurements, has been applied in all horizontal wells drilled. Clear identification of structural dips enabled the accurate reservoir model adjustment and allowed decisions on accurate trajectory corrections to be made while drilling.

A total of 33 horizontal injector-to-producer wells have been executed successfully. Three years from the inception of the new strategy, the average secondary production improved to 380 tons/day, which is higher than the best daily production during the course of primary production. The oil recovery is expected to double.

The application of the new horizontal well drilling pattern strategy, along with fit-for-purpose well placement technology, in the XH27 heavy oil reservoir has significantly increased the oil production and enhanced the recovery factor. The nearly obsolete heavy oil reservoir can be turned into an economically developed field.
Time-Lapse Diffusion Logs to Discriminate Reservoir Oil from Miscible Gas
Authors: Edwards John , Mutina Albina , Cheng Yuesheng , Gao Jinglin , Fordham Edmund , Freed Denise , Bachman Nate , Dolan Sean , Al Rashdi Yaqoob , Wilson Ove Bjorn , Haynes Byron , Looyestijn Wi m
Published: April 2012

A carbonate light oil reservoir surrounded by salt is without an active water or gas cap. The reservoir energy is limited. Without miscible gas flooding the initial production will drop quickly and the ultimate recovery is expected to be 10%. With miscible gas flooding the recovery is hoped to be in excess of 30%.

Oil desaturation measurements in observation wells near the injectors may give an early proof of this hypothesis, providing information on the miscible gas front and the efficiency of the sweep. However, the contrast between the reservoir oil and rich injected gas is small for monitoring with conventional cased-hole nuclear measurements. Cased-hole resistivity will not help, because the water saturation is low and not expected to change. An effort was made to qualify another measurement that could distinguish the two fluids to supplement the conventional logs: the diffusion of polarized hydrogen. The hydrogen associated with the longer chain molecules in the oil diffuses slower than the lighter hydrogen in the injected gas. Measuring the diffusion distribution of a hydrocarbon composition is possible with nuclear magnetic resonance (NMR).

A diffusion model was created using the liquid and gas compositions that were predicted using a PVT model as the proportion of injected gas to native oil was increased. This diffusion distribution indicated the liquid and gas phases could be distinguished and were therefore separately measurable for all the proportions modeled. This was verified with an NMR laboratory measurement of bulk fluids at various oil and gas proportions at reservoir conditions. The carbonate formation in this reservoir is characterized by heterogeneity; permeability variations of two orders of magnitude, and wide pore-size distribution. The hydrogen diffusion that is intended to discriminate the two fluids is partially suppressed in the formation pore volume due to restricted diffusion. The second phase of laboratory experiments consisted of quantifying the effect of the 90% dolomite 10% anhydrite rock on the diffusion of gas and liquid when constrained by the formation pore structure. The gas phase diffusion was reduced by a factor of four, and the liquid phase diffusion was reduced by 10%. Even with these reductions there was only little overlap of the diffusion distributions between the live reservoir fluid and injected sour gas that saturated the core plugs of porosity 21, 15, and 7. Laboratory tests also validated the NMR-transparency of special casing at reservoir conditions.
EOR Field Management Through Well-Planned Surveillance
Authors: Zwaan Marcel , Hartmans Rob , Schoofs Stan , de Zwart Bert Rik , Rocco Guillermo , Adawi Rashid , Saadi Faisal , Shuaili Khalfan , Lopez Jorge , Ita Joel , L’Homme Tanguy , Sorop Tibi , Qiu Yuan , van den Hoek Paul , al Kindy Fahad , Busaidi Said , Fraser John
Published: April 2012

PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs.

However, the interpretation of this advanced surveillance data and integration into well and reservoir management workflows is still challenging. This paper describes the results of the integrated workflows for the interpretation, modeling and integration of surveillance data in four EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling and monitoring through time lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging. This paper shows that the surveillance has contributed to the understanding of recovery mechanism in a pattern steam flood, it has supported decisions well-recompletions and work-overs and it has supported decisions on injection rates and surveillance planning in the chemical flood project.
Enhanced Computer-Assisted Model Calibration of Mukhaizna Heavy Oil Field
Authors: Pillai Taruna , Isdiawan Agusandi , Al Kindy Dalilah
Published: April 2012

The Mukhaizna field is a giant heavy oil field under steamflood for the past four years. A sector with NW-SE elongate low relief anticlinal structure from a complex full-field geological model with 200,000,000+ cells of channelized braided-fluvial sandstone deposition was upscaled to a dynamic model with 400,000+ cells. This sector model approximately 15% of the field production area, from the crestal part of the field comprises 87 producers and 78 Limed Entry Perforated injectors with several years of production and steam injection history.

A precursor for almost every reliable production forecast is a good history matched simulation model which becomes the cornerstone to optimize the decision making process. This paper describes an integrated and comprehensive simulation modeling workflow which was implemented to incorporate geological, petrophysical and dynamic uncertainties in a systematic way to calibrate the simulation model. Sensitivity analysis was performed to identify key static and dynamic input parameters. A computer assisted optimizer which applies experimental design and Tabu search techniques was used to test nonlinear and interaction effects of about 25 input parameters. This could be practically impossible using traditional sequentially modifying one-variable-at-a-time approach which always is cumbersome and may skew into an apparent solution even when none exists. During the iterative history matching process, uncertainties related to input parameters were constrained and modified from time to time to get an optimal solution. In addition to history matching 165 production/injection wells and 35 wells with pressure data, an attempt was made to match temperatures in 13 observation wells as well as heat breakthroughs in 70 patterns. The use of advanced techniques allowed us to minimize number of simulation runs and significantly reduced time to complete model calibration in less than couple of months which could traditionally take more than a year and still be limited in efficiently testing all possible combinations of input parameters.
Flow Characteristics of Viscoelastic Polymer Solution in Micro-Pores
Authors: Yin H. J. , Wang D. M. , Zhong H. Y. , Meng S. Y. , Jiang H. M. , Tang E. G.
Published: April 2012

Most experimental results demonstrate that the first normal stress difference of viscoelastic polymer solution is higher than the second normal stress difference. Therefore, the Upper-Convected Maxwell (UCM) equation is adapted to describe this property. The steady flow mathematical model of UCM fluids is established. The simulation results of the Finite Volume Method are given. The Finite Volume Method can effectively ensure the convergence together with improvement in the calculation accuracy. The Weissenberg number (We) of the Finite Volume Method can be calculated to 3.2, which is higher than by the Finite Differential Method to simulate the flow characteristics of polymer solutions. When using the Finite Differential Method, the Weissenberg number can only be less than 0.4, otherwise it cannot converge.

The contours of stream function and velocity of polymer solution with different Weissenberg number (We) or Reynolds number (Re) are drawn in three simplified micro-pore structures, expansion channel, contraction channel and expansion-contraction channel, respectively. The influence of Weissenberg number (We) and Reynolds number (Re) on microscopic sweep efficiency is studied. Numerical results show that the viscoelasticy of polymer is the main property that increases the sweep efficiency. With the increase in elasticity, the solution velocity of micro-pores at the corner of where the diameter suddenly changes is bigger; the flow region is enlarged, which is favorable for the residual oil becoming moveable, thereby increasing the micro-scale sweep efficiency. The higher the Reynolds number (Re) is, the larger the micro-scale sweep efficiency will be. But in reservoir condition, Reynolds number (Re) has little influence on improving the micro-scale sweep efficiency.

The above results are important to further understand the mechanism of driving fluid viscoelasticity increasing the Displacement Efficiency of porous medium.
Improving Sweep Efficiency in Fractured Carbonate Reservoirs by Microbial Biomass
Authors: Al-Hattali R. , Al-Sulaimani H. , Al-Wahaibi Y. , Al-Bahry S. , Elshafie A. , Al-Bemani A. , Joshi S.
Published: April 2012

Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones.

Three Bacillus licheniformis strains were tested with name codes; B29, B17 and W16. Their growth behavior using different nitrogen sources; yeast extract, peptone and urea was investigated. Glucose and sucrose were tested as carbon sources. Carbon/nitrogen ratios were optimized where it was found that sucrose was the carbon source that maximized bacterial growth at 2% concentration and yeast extract was the selected nitrogen source with concentration of 0.1%. The combination of B. licheniformis strain W16 in a minimal medium containing sucrose was the optimum condition for maximum cell growth within 10-12 hours of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was simulated by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Scanning electron microscopy was used to prove the growth of the microbial cells in the fracture after the experiment.

Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 27-30% of the residual oil was produced after 11 hours of incubation. This shows the high potential of using microbial biomass for selective plugging in fractured reservoirs.
Modeling the Geological Controls on Steam Flood Performance; An Example from a Field in South Oman
Authors: Shaikh MRF , Al Adawi R , Reiser H , Rocco G , Rodriguez F , Shuaili K , de Zwart AH
Published: April 2012

A field, located in south Oman, has a compact dome shaped structure with an oil column in excess of 200m. It produces highly viscous hydrocarbon from the fluvial Cambrian Haradh reservoir and represents an opportunity for Thermal EOR development. After an initial phase of steam injection, field data have shown that the response in the trial pattern is not homogeneous. In order to explain these observations a multidisciplinary effort has been undertaken to improve our understanding of the subsurface.

The information acquired in and around the injection area (an inverted 7-spot pattern), include connectivity trends from pressure data, temperature surveys, time lapse seismic, cores and well logs. After 20 months of steam injection a thermal response within the pattern is limited to only one producer well and two observation wells. The time-lapse seismic data is consistent with the field data observed from wells in the northern part of the pattern. The pressure data also indicate a predominant North-South connectivity trend within the pattern.

Four geological scenario models were built to test factors that may impact the understood distribution of temperature resulting from injection. The modelling workflow intends to assess the impact of 1) the internal structural dip and baffling lithologies within the Haradh Reservoir, 2) faulting within the Reservoir interval, 3) the Carboniferous Al Khlata immediately above the Haradh Reservoir and 4) the variation of Haradh Sandstone Facies and how these may impact fluid flow.

The models have been calibrated against historical data so as to ascertain if a given geological realization is a reasonable subsurface representation to reproduce the actual field production and pressure data. The results indicate that an individual scenario does not provide by itself an absolute explanation to the field observations to date. Instead, a combination of scenarios (fluvial facies and faulting) is considered to be a more feasible option to understand the field observations.
Macroscopic Recovery Mechanisms of In-Situ Combustion Process in Heavy Oil Fractured Systems: Effect of Fractures Geometrical Properties and Operational Parameters
Authors: Fatemi S. Mobeen , Kharrat Riyaz , Vossoughi Shapour , Ghotbi Cyrus
Published: April 2012

The In-Situ Combustion (ISC) as a thermal EOR process has been studied deeply in heavy oil reservoirs and is a promising method for certain non-fractured sandstones. However, its feasibility in fractured carbonates remained questionable. The aim of the present work was to understand the recovery mechanisms of ISC in fractured models and to evaluate the effect of fractures geometrical properties such as orientation, density, location and networking on the ISC recovery performance. Combustion parameters of a fractured low permeable carbonate heavy oil reservoir in Middle East called KEM; applied to simulation study. Simulator has been validated with KEM combustion tube experimental data and validated model modified to 3D semi-scaled combustion cells. It was found that in fractured models oxygen first flows into the fractures and then diffuses from all sides into the matrix. Combustion of the oil in the fractures produces water ahead of fracture combustion front which prohibits oxygen from early breakthrough through fractures into producer. Water imbibes into matrix and causes further oil drainage. Part of this oil imbibes into downstream matrices and the other part produces into producer through fractures. The oxygen diffusion/water imbibition based recovery mechanism is slower in production rates compare to conventional model recovery mechanism, and also results in lower quality of produced oil. It was found that ISC recovery was higher in the presence of networked fractures (presence of both longitudinal and traversal fissures) compare to the case of presence of either longitudinal or traversal fracture systems. Results show that ISC is more feasible in the case of densely fractured reservoirs such as those in the Middle East. Further, sensitivity analysis on air injection rate, formation thickness, injection well depth of perforation and also feasibility of water alternating gas (air), WAG, process for fracture model have been studied.
Wormlike Micelles for Mobility Control in EOR
Authors: Awang Mariyamni , Japper Azuraien , Kumar Sandeep , Dzulkarnain Iskandar
Published: April 2012

A major problem with polyacrylamide, the main polymer used in EOR, is its tendency to degrade under shear forces. Another polymer xanthan gum usually costs more than polyacrylamide and requires a biocide to prevent biodegradation. Micellar flooding has been reported extensively since the 70’s and as in the case of other chemical flooding, it has not been implemented widely due to the high cost of chemicals to form micelles. The high viscosity of the micelles also posed injection problems. However, strategic injection techniques can overcome the problem. The salinity of the formation water and temperature are also important parameters. All these usually restrict application of chemical EOR particularly surfactant and polymer flooding. However, current studies have shown wormlike-micelle surfactants such as those from cetyltrimethylammonium halides (CTAX) and cetylpridium halides (CPyX) can alleviate these problems. Wormlike micelles have been used in other areas such as home cleaner products and personal care products including shampoo and body wash due to its viscoelasticity. It also finds applications as fracturing fluids in oil fields. While earlier micelle studies proposed four or five components in forming stable micelles, the current studies showed that a surfactant and salt can form wormlike micelles. These micelles have the advantage of breaking and reforming under shear stress and therefore maintaining the viscosity. It is also viscoelastic and research has shown that viscoelasticity is able to reduce residual oil. This research studies the surfactants that can form wormlike micelles under high salinity, high temperature conditions and the salts that are required to form the micelles. Displacements studies conducted show good mobility control and work on injection strategy will be discussed.
Design of a Surfactant/Polymer Process in a Hard Brine Context: A Case Study Applied to Bramberge Reservoir
Authors: Tabary René , Douarche Frédéric , Bazin Brigitte , Lemouzy Pierre Maxime , Moreau Patrick , Morvan Mikel
Published: April 2012

Bramberge reservoir is a low temperature (40°C), high permeability (~1 Darcy) sandstone reservoir located in Germany. Waterflooded during several decades, oil production has been declining for the past few years. These conditions make this reservoir a good candidate for surfactant-polymer flooding.

Despite favourable attributes, the use of production brine, which exhibits very high hardness, as a re-injection fluid makes this project challenging and unique.

In this paper, we illustrate how this specific hurdle can be managed using a new strategy specifically developed for hard brines.

We show that surfactant/polymer formulations can be optimized in Bramberge re-injection brine despite its hardness with adequate properties for SP flooding (ultra-low interfacial tension and good solubility). The high level of divalent ions, and especially calcium ions, makes alkalis irrelevant for this project. We demonstrate using coreflood experiments that conventional injection strategies, successfully applied in soft brines (salinity gradient, etc…), and brine management options fail in these specific conditions because of the high chemicals adsorption. This high adsorption is showed to be strongly related to divalent ions.

We finally propose a successful alternative based on a careful selection of adsorption inhibitors. Using these additives, high oil recovery (94 %OOIP) was obtained together with low anionic surfactant and polymer adsorption. The overall technical performance is in line with conventional alkali-surfactant-polymer strategy in soft brine making this project very attractive and promising.

The process is currently in an optimization phase for pilot and field scale simulations allowing technical and economical optimization.
Alkali-Surfactant-Polymer Flooding Pilot Test in Southern Oman
Authors: Finol Jose , Al-Harthy Said , Jaspers Henri , Batrani Ahlam , Al-Hadhrami Hatim , van Wunnik John , Stoll Martin , Faber Rien , De Kruijf Alexander
Published: April 2012

Petroleum Development Oman is advancing a pattern flood pilot in a major sandstone field in Southern Oman that uses a chemical EOR flooding process to recover additional reserves. An EOR screening study showed that Alkali-Surfactant-Polymer is a viable technology for this viscous oil reservoir (90 cP). A successful ASP pilot test will pave the way to potentially implement the process in other sandstone fields in the Southern Oman Basin.

The ASP pilot test is a unique project in which two anionic surfactants have been specifically designed for the actual reservoir conditions. Laboratory tests indicated significant and comparable recovery from both outcrop and field cores. A high molecular weight polyacrylamide polymer designed to provide a favorable mobility ratio has also been tested at in-situ conditions. The primary objectives of the ASP pilot test are to validate laboratory results, demonstrate long term injectivity of the viscous ASP solution, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations and obtain data to calibrate dynamic models for accurate full-field predictions and economics.

The field pilot consists of a 1.4 acres inverted 5-spot pattern that includes 4 corner vertical oil producers, 1 central injector and 2 observation wells. The 53m producer-to-injector distance enables early ASP flood response (4 to 5 months) and ensures completion of the field trial within one year of injection. Injection/production facilities will be skid-mounted and located in the vicinity of the pilot wells. Pilot commissioning and first ASP injection is anticipated to start in mid 2014. This paper presents both subsurface and facility aspects of the ASP pilot test design, including four successful single-well ASP/SWCT field tests, one ASP flood MicroPilot, and the experimental results of oil-water-ASP emulsion separation experiments.
Modelling and Monitoring Experience on a 3-Year CO2 and Water Injection Pilot in a Mature Carbonate Field
Authors: Bourgeois Marcel J. , Gauer Pascal , Long Jerome , Prinet Catherine
Published: April 2012

In 2007, Total decided to launch a CO2 injection pilot, its objective being to prove the impact of CO2 injection on a mature depleted carbonate field. This field has been produced since 1982, mainly in natural depletion. The reservoir is Lower Cretaceous, low permeability carbonate rock with 20° API oil. The pilot pattern is an inverted 5-spot, with one central injector, 3 producers and one observer, the well spacing ranges from 300 to 700 m.

The main objective of the pilot was to observe and understand the effect of water and CO2 injection in a depleted carbonate reservoir, far below the Minimum Miscibility Pressure (MMP). This has been done in terms of microscopic oil recovery mechanisms, monitoring, and also field scale simulations. The microscopic work comprises secondary and tertiary CO2 SCAL data, and also a lean HC gas flood. PVT acquisitions include CO2 swelling tests, and slim tube data to estimate the MMP. Considering the risk of high mobility of immiscible CO2 in a heterogeneous reservoir, a WAG CO2 injection scheme was chosen and simulated.

This pilot was started in 2008, and has now 3 years of monitoring data. Breakthrough in HC phase was observed on the two proximal producers, but not on the most remote producer. Interestingly, as low salinity water was injected for a 18-month period after the CO2 injection, CO2 breakthrough was also measured in aqueous phase. SCAL data were matched by using alpha-factors (also called transport coefficients) in order to limit the stripping effect of the gas. Matching the 5-spot data enabled to quantify a strong multi-layer effect, as well as dissolution of CO2 in the injected water. From the lessons learned, we improved our understanding and capability to simulate and extrapolate WAG CO2 to other fields and conditions.
Minimum Miscibility Pressure Determination: Modified Multiple Mixing Cell Method
Authors: Teklu Tadesse Weldu , Ghedan Shawket G. , Graves Ramona M. , Yin Xiaolong
Published: April 2012

Hydrocarbon and non-hydrocarbon gas injection are among the most effective methods to enhance oil recovery. A key design parameter in any gas injection project is the minimum miscibility pressure (MMP). MMP can be measured in the laboratory with slim tube test, rising bubble apparatus and vanishing-interfacial-tension. Although laboratory measurements are more reliable, their high cost and longer period of time to get a few data sets made them less advantageous. There are numerous analytical, numerical, and empirical approaches devised to determine the MMP through studying thermodynamic behavior of reservoir and injection fluids in a given reservoir condition. Some numerical approaches need additional fluid and rock interaction properties such as relative permeability and capillary pressure.

Conceptually, miscibility between injected gas and reservoir oil can occur through three multi-contact mechanisms, namely condensing drive mechanism (CDM), vaporizing drive mechanism (VDM) and both condensing and vaporizing (CV) drive mechanism. Some models such as single-cell algorithm usually give overestimated MMP values since the model is based on the assumption that the drive mechanism is dictated only by CDM or VDM. In most cases, as we will see from the case studies of this research and reported by others as well, miscibility develops through both condensing and vaporizing (CV) driving mechanisms. Multiple mixing cell approach is a very effective way to handle CV drive mechanism. In this study, we modify the algorithm proposed by Ahmadi and Johns (2008), by including additional checking criterion. In spite of increased computational time overhead, our added checking criterion is found to be very useful to crosscheck the validity of the determined MMP, hence improve the reliability.
Process Design Aspects for Taking CO2 Enhanced Oil Recovery Offshore
Authors: Salim Mohammed , Harley John , Faizal Zairin
Published: April 2012

This paper presents the results of study work Granherne recently performed for an offshore carbon dioxide (CO2) Enhanced Oil Recovery (EOR) Project in the North Sea. In particular process design complexities are discussed for a new topside module comprising oil/gas separation, associated gas compression, dehydration with dense phase gas streams rich in CO2.

The importance of thermodynamic Equation of State (EOS) selection is highlighted, specifically for compressors and pumps in dense phase CO2 service. The selected HYSYS EOS results were benchmarked against a highly reliable Reference Fluid Thermodynamic and Transport Properties (REFPROP) database developed by National Institute of Standards and Technology (NIST). The comparisons are presented for compressibility, heat capacity, the heat capacity ratio and the enthalpy change across each compressor stage.

For the design of the gas dehydration unit, the experimental water equilibrium concentrations are compared with those predicted by commercially available simulators for a CO2-Water system. The HYSYS EOS did not model the acid gas-water system as accurately as Aqualibrium. The degasser flows for specifying the capacity of the LP Compression Train were under predicted by HYSYS EOS. The accuracy was improved by using the proprietary NRTL-SRK-Henry’s Law model in ASPEN PLUS.

The CO2 venting and depressurisation philosophy developed to avoid the formation of solid CO2 in the distribution headers is outlined. Also, the environmental aspects of CO2 rich gas cold venting versus flaring with assist gas is discussed.

The paper further highlights the technical design complexities compared to onshore CO2 EOR.