bluuebunny/crossref_metadata_2025 huggingface dataset:
Steam Assisted GOGD in Light Oil Reservoir - Pre-EOR Cold Daseline Importance and How We Achieved It
Authors: Saluja Jasmeet Singh , Hamm Ron , al Ghafri Salah , al Gharbi Mohammed , Diri Muhammad
Published: July 2010

Steam Assisted Gas-Oil Gravity Drainage (SAGOGD) trial is planned for a limited area of a giant producing light oil field in Oman. Oil production from this oil-wet fractured carbonate reservoir commenced in 1967, and recovery factor currently stands at approximately 20%. The SAGOGD process in a light oil fractured reservoir is complex and is comprised of numerous recovery mechanisms, with a number of these being uncertain and poorly understood. Very little world analogue data is available [1], and that, combined with large recovery process uncertainties make this ‘large pilot scale’ Phase 1 essential to mitigate the downside risk in a full-field development.

During Phase-1 it is planned to inject 2000t/d of steam by means of 4 vertical steam injectors. Oil, gas and condensed steam will be produced by 7 horizontal producers and 5 vertical back-up producers.

The magnitude of the SAGOGD production response is highly uncertain. Having the capability to accurately measure the incremental oil production response over this wide uncertainty range was considered to be a key success factor for the Phase 1 project. To accurately measure the incremental response required that a ‘no steam’ production response could be confidently projected into the future for a minimum of two, and up to five years. This task was made considerably more complex by the fact that historical GOGD well production profiles were often relatively unstable.

This paper describes the work carried out within PDO to ensure that one of the key Phase 1 success criteria – that being to measure the incremental oil due to SAGOGD – can be achieved over a primary evaluation period of two to five years. The discussion will include a description of efforts linked to optimization of cold GOGD performance (optimum oil rim management), well production stabilization (via installation of new production control hardware) and accurate measurement of total and individual well production levels (dedicated bulk and well-test facilities), and how this all came together to yield a stable cold production baseline which could be confidently projected into the future.
Impact of Shale Baffles During Pattern Steam Drive and Steam Assisted Gas Oil Gravity Drainage (SA-GOGD)
Authors: Al-Hinai Suleiman M. , Van Wunnik John
Published: July 2010

It is common practice to model shales in dynamic simulation models implicitly by assigning a global reduction factor to the sand's vertical permeability. Such an approach is required due to the complexity and computational limitations of modelling shales explicitly in large simulation models. The validity of this approach in the case of discontinuous shale baffles in a steam flood is the subject of this paper. The study concentrates on understanding the physics of flow in the presence of these discontinuous shales by conducting generic fine scale simulations for a water flood, a gas-oil gravity drainage system and a steam flood. The results show that in general implicit modelling of shales by an effective vertical permeability that is derived from single phase flow simulations cannot capture the flow mechanism and predicts a different oil recovery to models where shales are accounted for explicitly. For steam flooding implicit shale models take longer to heat the reservoir than explicit shale models; the main reason being that steam can percolate around shale baffles and so quickly achieve an elaborate network of continuous flow paths to the top of the reservoir. A parameter evaluation technique is worked-out that captures explicit shales correctly in an effective vertical permeability although this needs also tuning of (pseudo-) relative permeability parameters. Encouragingly, when a good history match is obtained for a bottom-up water flood by modeling the shales implicitly in the described way, these tuned implicit models also give good steam forecasts. The actual appearance of the floods can, however, be very different from the explicit appearance.
Fractured Carbonates: A Methodology to Evaluate Surfactant Performances
Authors: Chabert M. , Morvan M. , Tabary R.
Published: July 2010

Wettability alteration is a key method for recovering oil from naturally-fractured, oil-wet carbonate reservoirs. Many surfactants have been proposed for this purpose, including sulfonates, alkyl ammonium bromides or ethoxylated alcohols. Nevertheless, the very intrinsic link between oil recovery from an initially oil-wet rock and surfactant characteristics has been poorly studied. In particular, the interplay between rock wettability alteration and oil/water interfacial tension (IFT) reduction due to chemicals is not fully described.

We present a high throughput screening test to specifically address the problematic of surfactant effects on wettability. Automated contact angle measurements allow for the selection of successful candidates. From this screening, we propose a complete workflow using model minerals treated with crude oil and Amott/USBM measurements on outcrop carbonate cores. We demonstrate that taking into account surfactant effect both on IFT and on wettability gives superior results compared to focusing on aqueous solution spreading only. A qualitative correlation between results from high-throughput screening tests and Amott-Harvey wettability indexes variations is extracted. These results provide a consistent set of parameters to be included in future numerical simulations.
New Insights into Polymer Rheology in Porous Media
Authors: Seright R. S. , Fan Tianguang , Wavrik Kathryn , Balaban Rosangela de
Published: July 2010

This paper clarifies the rheology of xanthan and HPAM solutions in porous media, especially at low velocities. Previous literature reported resistance factors (effective viscosities in porous media) and an apparent shear thinning at low fluxes that were noticeably greater than expected from viscosity measurements. The polymer component that causes the latter behavior is shown to propagate quite slowly and generally will not penetrate deep in a formation. Particularly for HPAM solutions, this behavior can be reduced or eliminated for solutions that experience mechanical degradation and/or flow through a few feet of porous rock. Under practical conditions where HPAM is used for enhanced oil recovery, the degree of shear thinning is slight or non-existent, especially compared to the level of shear thickening that occurs at high fluxes.
Numerical Simulation of an Enhanced Oil Recovery Process of Toe to Heel Air Injection (THAI)
Authors: Rojas Jose , Ruiz Jorge , Vargas Jaime
Published: July 2010

This paper offers an innovative method to test various scenarios for toe-to-heel air injection wells, to meet the demands for new technology and methods using in-situ combustion coupled with steam injection. It presents research conducted over the last few years on the numerical simulation of the toe-to-heel air injection enhanced heavy oil recovery process.

Reservoir simulations were used to evaluate multiple variables and scenarios, leveraging the integrated workflow capabilities of software while maximizing the effective time for performance analysis.

Included are discussions of the workflow process, a description of base model details, well array testing results (i.e., four patterns combining horizontal and vertical wells), a comparison of injection air rate in the toe-to-heel air injection process versus a conventional in-situ combustion method, and sensitivities in oxygen concentration and injection rate, which led to increased recovery through the application of toe-to-heel air injection technology.

The effects of heterogeneities on the development of the toe-to-heel air injection process are also examined, along with multisegmented well model benefits demonstrated in the reservoir simulation software tool (ECLIPSE). Additionally, coke deposition during combustion was simulated, showing that toe-to-heel air injection does not affect the fluid flow dynamics process.

Based on our research study, this analysis of the best scenario for toe-to-heel air injection well placement efficiently produces nonconventional hydrocarbon accumulations by delivering increased process control on the combustion front.
Research on Reutilization Technology of Residual Polymer in Formation after Polymer Flooding
Authors: Caili Dai , Qing You , Yefei Wang , Fulin Zhao , Shuler Patrick
Published: July 2010

There is a large amount of residual polymer existing in the forms of solution, adsorption and entrapment in formation after polymer flooding. Then the water cut increases quickly along high permeable zone when displacing water. In order to improve sweep efficiency of water flooding and fully use residual polymer in formation, the reutilization technology of residual polymer in formation is proposed and developed. When the reutilization agents (including flocculating agent and fixed agent) are injected, they react with residual polymer and the floc units as well as the cross-linking units are formed which could block high permeability zone and control cross flow. As a result, the sweep efficiency of water flooding and oil recovery could be enhanced. In this paper, the optimized flocculating agent was selected through suspension experiments and the fixed effect for polymer was studied in sand pack cores, and the residual resistance factor was used as the evaluation criterion. The experiments showed that solid particles can be used as flocculating agent and the optimized flocculating agent is stabilized sodium clay; the cross-linking agent can be used as fixed agent and the optimal fixed agent is selected depending on formation temperature and the salinity. This technology was successfully applied in Henan oilfield, Shengli oilfield and Daqing oilfield. The water cut and produced polymer concentration decreased dramatically and oil production increased obviously. This technology which belongs to quaternary oil recovery is a preferred improved oil recovery technology after polymer flooding and has a broad application prospect.
Experimental Investigation of Biosurfactants Produced by Bacillus Species and their Potential for MEOR in Omani Oil Field
Authors: Al-Sulaimani H. , Al-Wahaibi Y. , Al-Bahry S. , Elshafie A. , Al-Bemani A. , Joshi S. , Zargari S.
Published: July 2010

Enhanced oil recovery techniques are usually controlled by the cost associated with them as the fluctuation in the oil price, over the last years, is now commercially accepted. Microbial Enhanced Oil Recovery (MEOR) is one of the technologies that can potentially be implemented with an exceptionally low operating cost. Apart from economical interests of MEOR, microbial bio-products are found to be more environmentally friendly. Besides, some of the bio-products are more chemically stable in reservoir conditions of high temperature and salinity.

In this study, biosurfactants produced by Bacillus licheniformis species isolated from oil contaminated soils from different parts of the Sultanate of Oman were investigated. Eight different production media using different sugars as carbon source such as: glucose, sucrose and cane molasses were tested on three of the potential strains to select the best medium that maximized the production of biosurfactants which was supported by the interfacial tension (IFT) reduction. All isolates were tested on their potential media to screen for the best biosurfactant producer among the available strains. It was found that the strain W19 gave the maximum IFT reduction (from 46.6 to 3.28 mN/m) in 16 hours of incubation when grown in medium 7.

Further studies on W19 were done to test the interaction of biosurfactant produced by this strain with porous media in core flooding experiments as a tertiary recovery stage. The results showed high potential of using this bacterium during ex situ MEOR applications where 10% of residual oil was recovered after injecting the biosurfactant solution. Further recovery was observed after concentrating the same biosurfactant solution where additional 13% of residual oil was recovered.
Numerical Modelling of Geomechanical Effects During Steam Injection in Sagd Heavy Oil Recovery
Authors: Zandi S. , Renard G. , Nauroy J. F. , Guy N. , Tijani M.
Published: July 2010

Steam Assisted Gravity Drainage (SAGD) is a thermal process that has found wide application in high permeability heavy oil or bitumen reservoirs, mainly in the Western part of Canada.

In this process, steam injection continuously modifies reservoir pore pressure and temperature, which can change the effective stress in the reservoir, resulting in a complex interaction of geomechanical effects and multiphase flow in the cohesionless porous media. Quantification of the state of deformation and stress in the reservoir is therefore essential for the correct prediction of reservoir productivity but also for the interpretation of 4D seismics used to follow the development of the steam chamber. On another side, this quantification is crucial for the evaluation of surface uplift, risk of loss of seal integrity, hydro fracturing and well failure. Simultaneous study and analysis of interrelated geomechanics and fluid flow in the reservoir are thus crucial for the management of the process at different stages.

The objective of this paper is to show the importance of taking into account the role of geomechanics in the numerical modelling of SAGD and to provide a better description of the rock contribution to fluid flow in this process. A geomechanics- reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case.
A Case Study of ASP Multi-well Groups’ Development Characteristics in Daqing Oil Field
Authors: Rue Song , Dianping Xu , Xiwen Zuo , Zhanlin Ma , Hua Qing , Yali Liu
Published: July 2010

Alkali-Surfactant-Polymer (ASP) pilot and enlarged field tests are all successful in Daqing Oil Field, demonstrating ASP process can greatly enhance oil recovery by 20% OOIP and bring more economic benefits. But the previous tests were all carried in one group of wells which couldn't reflect performances and adaptability of ASP industrial application. Therefore, the commercial field test in multi-well groups with homemade surfactant has been carried out to study performances, scaling characteristics and matching adjusting technologies and to accelerate industrial generalization of ASP flood. The test shows that ASP flood is suitable for the reservoir whose connecting proportion of river channel sand is above 70%, and permeability is over 0.3um2. The larger the well space is, the longer time alkali takes to transfer in reservoir, which results in serious chromatographic separation, scaling, and decrease of injecting-producing capability. Development result can be improved by fracturing on injectors and producers, ceramsite fracturing proppant being the best choice, and by low-carbon mixed organic acid on heavily scaled producers during the late development stage to remove blockage, but the influence of scale can't be totally eliminated. Due to lateral and inter-layers’ heterogeneity in the reservoir, less recovery has been achieved than in the pilot test. We can know from the test that if the well-space is shortened in industrial application, and anti-scaling method is optimized, oil recovery will be further improved.
Experimental Investigation of Asphaltene Induced Permeability Reduction
Authors: Hayashi Yoshihisa , Okabe Hiroshi
Published: July 2010

CO2 injection is one of efficient enhanced oil recovery (EOR) methods among gas flooding, however, asphaltene precipitation during CO2 injection might lead to production loss and reduced efficiency. To understand the mechanism of asphaltene deposition is necessary to develop effective engineering practice for minimizing the formation damage and to design the treatment program for restoring well productivity. The paper presents the development of the experimental apparatus for asphaltene precipitation during pressure decline and gas injection in addition to the results of asphaltene phase behavior and coreflood tests to identify the dominating factors associated with permeability reduction. Asphaltene phase behavior is studied to determine the relationship among pressure, temperature and asphaltene precipitation. Asphaltene onset pressure is measured by Solids Detection System (SDS). The pressure decline induces asphaltene deposition and the consistent result is obtained by the measurement of asphaltene content using SARA analysis. These results are used to estimate Asphaltene Deposition Envelope (ADE). ADE reveals the risk of asphaltene deposition when the pressure is decreased. It is a useful measure to predict flow problem in the reservoir and at the facilities due to asphaltene precipitation. The reversibility of asphaltene precipitation and re-dissolution is also investigated. Gas injection coreflood experiments are conducted on sandstone and carbonate cores to evaluate the asphaltene precipitation and its permeability reduction. Asphaltene is selectively deposited near the inlet of the core for CO2 injection, while asphaltene is equally distributed in the core for the hydrocarbon (associated) gas injection. Additional experiments confirm that the permeability is decreased with increase of asphaltene precipitation. The experimental investigation is necessary to further understanding of the asphaltene behavior in order to prevent asphaltene induced permeability reduction when the risk of asphaltene precipitation is expected due to gas injection and pressure decline.
Integrated Heavy Oil Production with HTL Field-Located Upgrading – Using Upgrading By-Products as a Fuel Source for EOR
Authors: Kuhach J. , Koshka E. , Pelham J.
Published: July 2010

Ivanhoe Energy Inc.'s proprietary HTL upgrading technology is designed to cost effectively process heavy oil in the field and produce a stable upgraded synthetic oil that meets pipeline requirements. Upgrading by-products are converted on-site to steam for enhanced oil recovery (EOR). In developed markets, HTL improves the economics of heavy oil production by reducing or eliminating the need for natural gas and diluent, and by capturing the majority of the heavy to light oil price differential. In remote areas, where natural gas and diluent are not available, integrated HTL production frees otherwise stranded resources. HTL accomplishes all of this at a much smaller scale, at lower per barrel capital costs, and with less impact on the environment compared with conventional technologies.

After years of piloting, development and commercial demonstration, HTL upgrading is in the process of commercial implementation. Integrated HTL/thermal EOR projects are progressing in Canada and Ecuador, illustrating applications in developed and undeveloped markets, respectively. This paper provides a description of the HTL upgrading process, with a particular focus on energy integration with upstream operations.
Fishing Coiled Tubing From a Live Gas-Condensate Well With Coiled Tubing While Under Production
Authors: Kang B. I. , Murugappan B. S. , Kwon O. K. , Sinn G. J. , Foster I. , Robinson L. , Elliott J. B. , Hampson R. , McKinnon B. L.
Published: July 2010

This case study examines the techniques required to recover a coiled-tubing (CT) fish from a live condensate well (using CT) without actually killing the well.

These procedures were recently implemented offshore Vietnam, where an extremely fluid-sensitive formation prevented killing the well because the formation would not likely have recovered. Using the techniques described in this paper, a 1.50-in. (38.1-mm) CT fish 9,177 ft (2797 m) long was successfully recovered from a well while keeping the well on production throughout the operation. This was achieved using temperature-setting gel as an isolation barrier against wellbore pressure in the fish, which saved the customer the approximately USD 20 million in costs associated with the alternative solution of drilling a new well.

This paper outlines the equipment required and factors to consider while designing the job, as well as describing the surface handling procedures once the fish is brought to surface. Particular problems with operating in a live condensate well are also highlighted. Finally, safety methods will be discussed throughout the paper to maintain a dual barrier against wellbore pressure during all phases of the job, including the use of gel as an isolation barrier.
How EOR Can be Transformed by Nanotechnology
Authors: Fletcher A. J. , Davis J. P.
Published: July 2010

Nanotechnology has the potential to transform EOR mechanisms and processes. At present there are two major nanotechnology paradigms derived from mechanical engineering and the biological sciences perspectives. However, a new focus within nanotechnology is emerging which could be called geomimetics. We can define geomimetics as employing the principles of geosystems to create and develop new and novel processes and materials. In a wider sense this involves copying the principles of geosystems into technology to compliment the natural environment.

This geomimetic perspective of nanotechnology incorporates the long and distinguished history of colloid and surface science that has underpinned oil recovery and EOR. We give a concise definition of nanotechnology and demonstrate how it is applicable to EOR.

Through consideration of complexity and systems thinking, we develop a process based method of representing complicated phenomena to help identify the critical processes which control EOR. We construct a hierarchy from fundamental surface forces leading up to processes such as coalescence, phase swelling and film drainage. This hierarchy constitutes a mapping from fundamental molecular forces onto petroleum engineering concepts. In general this hierarchy is spatially-temporally ordered, although particular attention to the overall context and fluid / rock history is needed when mapping wetting and spreading phenomena. We identify critical processes and identify performance measurement criteria to monitor these processes.

We present a conceptual study and demonstrate how nanoscale processes can impact flow behaviour. We introduce the concept of Q analysis and highlight the importance of metaphorical discourse. Processes at the nanometre – micrometre scale including wettability, coalescence, Marangoni phenomena, mass transfer effects and transient phenomena are related to EOR. We argue it is at this scale, and with these phenomena, that an understanding of oil phase distribution, oil drop mobilisation, oil bank formation and oil bank migration is to be achieved for EOR processes.

We outline the potential of nanotechnology to transform the design and execution of chemical EOR. Through nanotechnology, we make explicit the connection between the disciplined study of fundamental molecular forces and the practical application of petroleum engineering.
Optimal Heavy Oil Waterflood Management May Differ From that of Light Oils
Authors: Vittoratos E. , West C. C.
Published: July 2010

Current paradigms and regulatory mandates implicitly assume that waterflood reservoir management practices successful in light oils can be extended unmodified to heavier oils. In particular, complete voidage replacement is considered optimal irrespective of oil chemistry; furthermore, it is assumed that the Buckley-Leverett multi-phase flow formulation, successful in light oils, is equally applicable with heavier crudes. Surprisingly, despite the paramount importance of these concepts to successful reservoir management, there is little public domain documentation on any empirical tests of these assumptions using field data. We here report that our ongoing empirical examination has accumulated observations that suggest that optimal heavy oil waterflood management may differ from that of light oils.

The literature has anecdotal accounts of the difficulty of maximizing oil recovery for heavy oil reservoirs while attempting to achieve complete voidage replacement. In the North Slope of Alaska, efforts to maximize oil production early in the waterflooding of isolated hydraulic blocks have led to a VRR < 1. For heavy oils, we have previously identified a flow regime with WOR ∼ 1 for extended periods of time prevalent for reservoirs worldwide. In Alaska, where we possess detailed fluid, well and reservoir information, we have correlated this regime with hydraulic units with incomplete voidage replacement. The WOR ∼ 1 flow regime can be interpreted as a water-in-oil emulsion flow which is intrinsic to the water/oil system chemistry and not to the details of the reservoir stratification, explaining its widespread prevalence. Laboratory heavy oil waterfloods with a VRR = 0.7 recover more oil than those with VRR = 1, and provide evidence of in-situ water-in-oil emulsion formation. Furthermore, the laboratory floods suggest that the recovery prize for optimal voidage strategy may be estimated by a simple heuristic equation: optimal recovery process (VRRopt) ∼ recovery pure waterflood (VRR = 1) + recovery pure solution gas drive (VRR = 0).
Non-estrogenic Alkylphenol Derivatives for EOR
Authors: Berger Paul D. , Lee Christie H.
Published: July 2010

Alkylphenol ethoxylates and their derivatives have been used for many applications including Enhanced Oil Recovery in the past. The popularity and widespread use of these materials has decreased dramatically over the past 10 years because of the finding that these materials are estrogenic or precursors to estrogen mimics. It has now been found that a slight variation in the structure of these materials can render them non-estrogenic and also prevent their degradation products from being estrogenic without changing the surfactant properties. The resulting alkylphenol alkoxylates, alkylphenol ether sulfate and alkylphenol ether sulfonates have been shown to give low interfacial tensions over a wide range of salinities, temperatures and crude oil compositions making them a low-costs, effective, easily manufactured and safe materials to be used alone or in combination with other surfactants for Alkaline Surfactant Polymer and Surfactant Polymer Flooding. Although the application of these materials is not restricted to IOR, specific examples directed to these applications will be discussed along with the structures and properties of these surfactants.
New Method for Fluid Level Depression Test Interpretation Based on Modern Multiphase Flow Calculation Techniques
Authors: Khasanov M. M. , Krasnov V. A. , Khabibullin R. A , Pashali A. A , Semenov A. A.
Published: July 2010

Acoustic measurement of annulus liquid level is one of the simplest measurement techniques that are used to monitor and analyze well performance without stopping the production.

However, the free gas at pump intake, and more important – the gas flowing up the annulus head reduce the accuracy of bottom hole flowing pressure estimation. One of the important reasons for this is the high uncertainty of gas/liquid gradient calculation in the annulus. Practically, the technique that is widely used to reduce this error is the fluid level depression test (FLDT) – using an acoustic measurement device while recording the annulus head pressure buildup rate having the annulus head valve closed.

To increase the estimation accuracy of the bottom hole flowing pressure, new method of depression test interpretation is introduced. The method implements modern techniques of multiphase flow calculation and inverse problem regularization algorithm. Well performance additional data could also be obtained from this method of interpretation (GOR, annular gas rate, and in many cases separation efficiency at the ESP intake).

Comparing the results obtained using this method to actual measurements using multiphase flow meter and pump intake gauges has verified the confidence level of the method and our understanding of well processes during the FLDT.

The fluid level depression test and the new interpretation method enable us to improve calculations accuracy of well potential production rate, resize ESP more efficiently and increase well production. The fluid level depression test is widely used in Rosneft oilfields. Considering results of about 4000 tests we concluded that the reliability of well data after proposed interpretation technique is 97,5%. This caused in 15% increase of oil production potential achievement.
Low Salinity Water Flooding: Proof Of Wettability Alteration On A Field Wide Scale
Authors: Vledder Paul , Fonseca Julio Carrera , Wells Terence , Gonzalez Ivan , Ligthelm Dick
Published: July 2010

Low salinity water injection is an emerging EOR technology, applicable to mixed-to-oil-wet sandstone reservoirs. Flooding with low salinity water causes desorption of petroleum heavy ends from the clays present on the pore wall, resulting in a more waterwet rock surface, a lower remaining oil saturation and higher oil recovery.

A secondary flood application is discussed in the Omar field in Syria showing a change of wettability from oil wet to a water-wet system. This change in wettability is supported by the observation of dual steps in watercut development. In between the two steps the watercut was constant. This behaviour is a known indicator of changing wettability. Moreover, direct connate water banking measurements confirm the change. The field observations are supported by spontaneous imbibition experiments in core material and a single well Log-Inject-Log test in an analogue field.

From the field observations, the change in wettability is estimated to be nearly complete, leading to an associated incremental recovery of 10–15% of the Stock Tank Oil Initialy In Place (STOIIP).

The significance of this work is that this is one of the very few documented proofs of concept on a reservoir scale. Work is ongoing to prove this concept in a tertiary flood as well.
Gas Injection Project in the Kharaib B Reservoir of the Giant Al Shaheen Field
Authors: Mogensen Kristian , Hood Paul , Jones Robert , Noman Rashed
Published: July 2010

This paper describes the successful implementation of a lean gas injection trial in a long horizontal well and the subsequent expansion of hydrocarbon gas injection in the low-permeability Kharaib B carbonate reservoir of the Al Shaheen field, offshore Qatar.

The main objectives of the injection trial were to determine whether premature gas breakthrough would occur in the neighbouring production wells and whether water injectivity after the gas flood would be reduced as a result of the presence of high gas saturation around the injection well. During a 6-month trial period, some 1.7 Bscf of produced gas was reinjected into a trial well. The neighbouring production wells, located some 1,000 ft away, have seen increased production due to pressure support, without suffering from premature gas breakthrough. Data suggest that the reinjected gas may have redissolved into the reservoir oil and that the pressure response is linked entirely to water injection. Furthermore, water injectivity was comparable to the nearby water injection wells; hence, gas injection did not seem to have a negative impact on the subsequent water flooding efficiency.

Encouraged by the positive results of the trial, gas injection is being expanded to a larger number of wells belonging to five different platform locations and encompassing three carbonate reservoirs of the Al Shaheen field. Prediction of gas injection performance has been carried out with compositional reservoir simulation models, which required non-equilibrium initialisation to account for lateral reservoir fluid property variation, a tilted free water level, and a large transition zone. The project started early 2010 using the currently available lift gas pressure. High-pressure gas injection, implemented as a water-alternating-gas (WAG) scheme, will take over once the required surface modifications have been made.
Experimental and Simulation Of CO2-Foam Flooding In Fractured Chalk Rock At Reservoir Conditions: Effect Of Mode Of Injection On Oil Recovery
Authors: John Zuta , Ingebret Fjelde , Roman Berenblyum
Published: July 2010

Field trials and laboratory tests of CO2-foam have shown some success. A number of CO2-EOR field trials with either miscible or near miscible gas injection have shown that foam can lower the mobility of CO2 and improve the macroscopic sweep efficiency. However, not much work about CO2-foam flooding in fractured chalk reservoirs with low matrix permeability have been published in the literature. During CO2-foam flooding of fractured chalk media, it is expected that the injected fluids will flow in the high permeability fractures where foam will preferentially be formed. This will increase the local resistance to flow and divert more of the CO2 and CO2-foaming agent solution into the low permeable matrix.

This paper presents results from laboratory experiments and simulation studies carried out to investigate the effect of mode of injection on oil recovery during CO2-foam flooding of water flooded fractured chalk models at reservoir conditions. The fractured model was created by drilling a hole through the centre of the plug and homogeneously packing it with glass beads. The CO2-foam process was conducted by injecting pre-formed foam either horizontally or vertically into the fractured models at 340 bar and 55°C. Pure CO2 and WAG processes were also carried out on similar fractured models to establish base case behaviours at the same conditions.

Laboratory results show that additional oil after water flooding is recoverable by injecting pre-formed foam either horizontally or vertically (from the top) in the CO2-foam processes when compared to the injection of pure CO2 and CO2-WAG at the same effective permeability and CO2 volume. In the simulation studies carried out with CMG's compositional reservoir simulator STARS on a similar fractured model used in the laboratory experiments, the results from the core floods were quantitatively confirmed. Additional simulation carried out in large matrix blocks on the field scale showed that CO2-foam can recover additional oil at reservoir conditions. However, the adsorption of the foaming agent can make the CO2-foam process inefficient.
Anti-corrosion Technique of Injection Well In CO2 Flooding
Authors: Fuzhou Wan , Gao Chunliang , Yu Lei
Published: July 2010

CO2 gas has low viscosity, flows very freely and is corrosive. This paper presents two innovative and economical anti-corrosion techniques of injecting (flooding with) CO2 under conditions of high temperature, high pressure and the CO2 cause corrosion. The down hole packer was fabricated with the CO2 corrosion resistant chrome-plated alloy steel. Chromium is one of the most hard metal and corrosion resistant material, the equipments and devices down hole were chrome-plated that can be also wear-resistant effect. and the general rubber design. The casing tubing annulus injected the imidazoline type corrosion inhibitor to keep the pressure balancing, anti-corrosion situation to protect tubing pipes and casing pipes. This anti-corrosion technique of injection well in CO2 flooding ensured the packer seal long-term security and achieved the CO2 gas safety injection.
Performance and Economic Evaluation of Cyclic Pressure Pulsing in Naturally Fractured Reservoirs
Authors: Artun E. , Ertekin T. , Watson R. , Al-Wadhahi M. , Miller B.
Published: July 2010

Gas cyclic pressure pulsing is an effective EOR method in naturally fractured reservoirs. A limited number of studies concerning this method in the literature focuses on specific reservoirs and the optimum operating conditions have not been broadly investigated. In this study, we present a detailed parametric study of the process from both operational and reservoir perspectives. Incremental oil production, peak oil rate and net present value (NPV) are considered as the important markers for the performance criteria. The necessary analyses are performed for a single-well, dual- porosity, compositional reservoir model. In the first part of the study, parametric studies are conducted to develop a better understanding of the operational parameters affecting the process performance, in the shallow, naturally fractured, and depleted reservoirs of Big Andy Field in Eastern Kentucky. These include analyses of various design parameters such as soaking period, cycle rate limit, number of cycles, cycle and cumulative injected gas volumes. In the second part of the study, reservoir characteristics are investigated. Comparative discussions are presented between cases with CO2 and N2 as the injected gas on reservoir fluids of different compositions (heavy, black and volatile oils). Influences of area, thickness, fracture/matrix permeabilities, initial reservoir pressure and temperature on the process are studied. It is observed that N2, as a lower-cost gas, would be a better choice than CO2 in the Big Andy Field. With the oil price used in this study, the cost of injected gas becomes relatively insignificant in economic considerations. Increased income due to increased oil production overcomes the increased costs with higher volumes of gas. The way reservoir characteristics affect the process performance is very similar in cases with CO2 and N2, but differs significantly in different reservoir fluids. Thicknesses ranging between 20 and 50 ft produced more favorable results. A higher efficiency was observed with smaller drainage areas (5-8 acres) in the presence of heavy oil. For the cases with volatile and black oil, it is seen that the process efficiency is not significantly altered by the area. The phase behavior of the reservoir fluid is very important for the performance of the process. Initial pressure/temperature of the reservoir, and therefore, the initial fractions of gas/liquid phases affect the process efficiency in a more pronounced manner.
Modeling of Transport of a CO2-Foaming agent during CO2-Foam Processes in Fractured Chalk Rock
Authors: John Zuta , Ingebret Fjelde , Roman Berenblyum , Vartdal Leif Hogne , Henrik Ovesen
Published: July 2010

In fractured chalk reservoirs with low matrix permeability, molecular diffusion and retention of the foaming agent will control the transport of the foaming agent solution from the fracture into the matrix as well inside the matrix. However, the transport of CO2-foaming agents and how much of the matrix will be contacted by the CO2-foaming agent in fractured chalk reservoirs has not been investigated.

This paper presents both experimental and numerical simulation studies performed to investigate the transport of a CO2-foaming agent from a fracture into an outcrop chalk core plug at two different temperatures; room temperature and 55°C. Plugs with different water saturations were used; Sw=100%, Sorw (20-30%) and Swi (14%). The fracture was created by transferring plugs with different diameters into cylinders with an annulus space around the plugs. The fracture volumes were filled with different initial concentrations of CO2-foaming agent solutions. The experiments were monitored by taking fluid samples from the space above the fracture at different times until constant foaming agent concentration in the fractures. At different exposure times, the plugs were demounted and samples taken from the outer, middle and centre portions along the whole lengths of the plugs. These samples were analysed for foaming agent concentration to determine the transport rate in the matrix.

Results indicate that the transport of the foaming agent solutions into the plugs depend on the diameter of the plugs, temperature and amount of oil remaining in the plugs. The transport of the foaming agent solution from the fractures into the plugs was also modelled with the CMG's commercial reservoir simulator STARS. A good match between experimental and modelling results was obtained. Based on simulated results, the foaming agent was also observed to penetrate and reach the middle sections of the plugs with and without oil. Additional simulation results show that on the field scale, the transport of the foaming agent will depend on the size of the matrix blocks, rock type, and adsorption of the foaming agent as well as the presence of oil.
Managing Field Development Uncertainty in the Geologically Complex Stringer Sands in Offshore Saudi Arabia
Authors: Warren Phillip B. , Al-Ghamdi Faisal A.
Published: July 2010

This paper will describe how new technologies, such as geosteering, seismic imaging and new drilling techniques, are being pursued to improve overall net sand reservoir contact and production improvements in horizontal wells. These technologies have been implemented in offshore wells to obtain valuable geological information, improve well placement, and minimize sidetracks by reducing uncertainty. The geologically complex stringer sand reservoir is unconsolidated sandstone with a permeability of 3-5 Darcy. Proper well placement and minimizing costly sidetracks are critical to the success of this offshore field.

Improvements in the well placement of horizontal wells within stringer sand reservoirs have improved immensely in the offshore fields of Saudi Arabia. New technologies and techniques involving geosteering, seismic imaging, and well design have been evaluated and field tested, and has improved the net to gross sand ratio from 50% to over 80% with a corresponding increase in production of over 50%, with opportunities for additional improvement.
Design and Implementation of the First CO2-EOR Pilot in Abu Dhabi, UAE
Authors: Al Hajeri Salma , Negahban Shahin , Al-Yafei Ghaniya , Al Basry Ali
Published: July 2010

Carbon Dioxide (CO2) Enhanced Oil Recovery (EOR) process is most likely to become the preferred hydrocarbon recovery process in future in Abu Dhabi. The complexity and cost of implementing large scale EOR projects require the development of a detailed EOR strategy, clearly defined targeted objectives, a visionary work-plan (roadmap) and staged evaluation prior to full field commercial implementation. Abu Dhabi Company for Onshore Oil Operations (ADCO) is in the process of conducting the first Middle-East CO2-EOR pilot in an onshore complex carbonate reservoir.

This paper discusses the design and implementation of the first ADCO CO2-EOR Pilot Project which addresses key technical and business uncertainties and risks associated with CO2 injection in ADCO reservoirs in the future. The pilot was considered the best approach to evaluate feasibility of this EOR approach on a field scale in addition to other verifications through laboratory and simulation studies.

The project started with a company-wide screening study which attempted to identify both the most appropriate EOR option for ADCO reservoirs and the best reservoir candidates. Subsequently, an in-house simulation study was conducted to confirm the best identified candidate reservoir. The Roadmap defined studies required to fill the required data gaps. Advanced CO2-PVT, Asphaltene and SCAL studies were conducted to reduce the uncertainties related to CO2 injection. The pilot objectives and constrains were clearly defined at the early stage of the project. Challenges of obtaining the required CO2 volumes for injection were overcome.

A history matched compositional reservoir simulation model was used as an effective tool to design and optimize the pilot. Sufficient time and effort were expended in the pilot design and optimization in order to meet the implementation objectives in a timely manner. These include drilling of the wells, construction of the surface facilities, development and execution of the surveillance and monitoring plan and finally the operation of the pilot.

This paper outlines the design and implementation of the first ever Middle-East CO2-EOR pilot in an On-shore complex carbonate field in Abu Dhabi, UAE.
A Comprehensive Kinetic Theory to Model Thermolysis, Aquathermolysis, Gasification, Combustion, and Oxidation of Athabasca Bitumen
Authors: Kapadia Punitkumar R. , Kallos Michael S. , Gates Ian D.
Published: July 2010

Extraction and upgrading of bitumen in Alberta, Canada uses large amounts of energy, generates huge volumes of acid gas, consumes massive volumes of water, and is costly. Most bitumen produced in Alberta is converted in surface upgraders to synthetic crude oil (SCO), a 31 to 33°API oil product. Next, SCO is converted to transportation fuels and lubricants in conventional refineries. Bitumen upgrading requires hydrogen. Today, most of the hydrogen is produced by steam reforming of methane which requires huge amounts of methane. Alternatively, hydrogen can be generated by in situ gasification of bitumen. Gasification is potentially more energy efficient with reduced emissions since acid gases are sequestered to some extent in the reservoir. Also water usage is lowered and heavy metals and sulfur compounds in the bitumen tend to remain downhole. The overall objective of this research is to understand and optimize hydrogen generation from bitumen reservoirs. In situ technologies that convert bitumen to hydrogen will have direct application in bitumen upgrading, use as feedstock for ammonia and other chemicals, and may be a key step to start a hydrogen economy. One key step towards the design of in situ hydrogen generations processes is the construction of the reaction scheme together with the associated kinetic parameters. Here, a unified kinetic model that takes pyrolysis (thermolysis, thermal cracking), aquathermolysis, gasification, and combustion (oxidation) of Athabasca bitumen has been assembled. The model has been calibrated against 7 experimental and plant data sets (with 149 data points in total) and implemented in a thermal reservoir simulator. The unified kinetic model was developed by performing a global match of the reaction scheme and kinetic parameters against all available pyrolysis, aquathermolysis, gasification, combustion, and oxidation data.
Surfactant-Induced Spreading and Wettability Effects in Condensate Reservoirs
Authors: Zheng Y. , Rao D. N.
Published: July 2010

Condensate blockage is known as a serious problem in gas condensate reservoirs due to the depletion of reservoirs to pressures below the dew point. It reduces gas phase relative permeability and consequently results in the loss of gas productivity. The objective of this study was to identify and attempt to remedy this blockage problem through reservoir wettability determination and wettability alteration by using surfactants in the condensate buildup regions. Experiments were performed at ambient conditions by using stock tank condensate sample, methane, synthetic reservoir brine, and quartz substrate.

In this study, both the spreading coefficient and wettability were measured to characterize the influence of anionic and nonionic surfactant on interfacial behavior. The contact angles were experimentally measured using Dual-Drop-Dual-Crystal (DDDC) technique. The Drop Shape Analysis (DSA) and capillary rise technique were used for measuring oil-water, watergas and gas-oil interfacial tensions. An advancing angle of 152° obtained from the experiments indicated that this sandstone condensate reservoir had a strong oil-wet nature. Anionic and nonionic surfactants at the concentration levels of 500, 1500, and 3000 ppm were tested in the experiments. Results showed that although spreading coefficients were all positive for the condensate-brine system with/without surfactants, they decreased after the surfactants application. This implies that oil recovery is still enhanced from surfactants usage in this strongly oil-wet system. Also, all three concentrations of anionic surfactant were shown to alter the wettability of quartz surface from strongly oil-wet to intermediate-wet or weakly oil-wet. However, no wettability alteration was found after nonionic surfactant usage. The key finding from the ambient condition experiments is that the sandstone reservoir wettability is altered from strongly oil-wet to intermediate-wet or weakly oil-wet by using an anionic surfactant.