Oil Column Research Articles

Asphaltene gradients and tar mat formation in reservoirs under active gas charging

Based on downhole fluid analysis (DFA) measurements and advanced asphaltene science, a new modified Flory–Huggins regular solution model that has been referred to as the Flory–Huggins–Zuo equation of state (FHZ EOS) has successfully been developed and used to delineate reservoir connectivity recently. It provides the industry's first simple explicit EOS for predicting asphaltene grading and has proven reliable to predict connectivity in equilibrated oil columns. In this paper, the methodology for equilibrated reservoirs is extended to a nonequilibrium oil column, especially for a reservoir under active charging of biogenic gas. Based on the properties computed by the Peng–Robinson EOS with methane influx, the FHZ EOS for asphaltenes – originally formulated for equilibrium columns – is used to model the asphaltene (optical density) gradient in the nonequilibrium oil column. In addition, the FHZ EOS with the same parameters is employed to check whether the predicted asphaltenes can be stably dispersed or suspended in the oil. The predicted results show that the asphaltenes at the base of the oil column are unstable because late gas charging (diffusing downward) results in a reduction of oil solvation power for asphaltenes and makes asphaltenes concentrated near the base of the oil column. The concentrated asphaltenes are too much for the oil and they tend to be flocculated out to form an asphaltene-rich phase and a tar mat could form if asphaltene flocculation is severe over geological time.

Modeling and optimization of an industrial hydrocracker plant

The main objective of this study is modeling and optimization of an industrial Hydrocracker Unit (HU) using Artificial Neural Network (ANN) model. In this case some data from an industrial hydrocracker plant were collected. Two-thirds of the data points were used to train ANN model. Among the various networks and architectures, two multilayer feed forward networks with Back Propagation (BP) training algorithm were found as the best model for the plant. Inputs of both ANNs include fresh feed and recycle hydrogen flow rate, temperature of reactors, mole percentage of H 2 and H 2S, feed flow rate and temperature of debutanizer, pressure of debutanizer receiver, top and bottom temperature of fractionator column and pressure of fractionator column. The first network was employed to calculate the specific gravity of gas oil, kerosene, Light Naphtha (LN), Heavy Naphtha (HN), gas oil and kerosene flash point and gas oil pour point. The second network was used to calculate the volume percent of C 4, LN, HN and kerosene, gas oil and fractionators column residual (off test). Unseen data points were used to check generalization capability of the best network. There were good overlap between network estimations and unseen data. In the next step of study sensitivity analysis was carried out on plant to check the effect of input variables on the plant performance. In this case temperature was found as the most affecting parameter in the plant. Finally optimization was performed to maximize the volume percent of gas oil, kerosene, HN and LN production and to identify the sets of optimum operating parameters to maximize these product yields. Optimum conditions were found as feed flow rate of 113.2 m 3/h, reactor temperature of 413 °C, hydrogen flow rate of 111.3 MSCM/h and LN () feed vol.% of 9.22.

Preparation and characterization of spherical mesoporous ZrO2-Al2O3 composites with high thermal stability

Spherical mesoporous ZrO2-Al2O3 composites containing different zirconia content have been synthesized by an oil-column sol-gel method. A mixed alumina-zirconia hydrosol and hexamethylenetetramine solution were mixed together and added dropwise into a hot oil column. Due to the surface tension, spherical gel particles were formed in the oil column. The spherical gel particles were then aged and washed by deionized water and dried at 120 °C for 12 h and then calcined at 600 °C for 8 h, 960 °C for 8 h or 1200 °C for 12 h. X-ray diffraction and nitrogen adsorption-desorption measurements indicated that the presence of zirconia prevents the sintering of alumina and the obtained ZrO2-Al2O3 composites have much larger surface areas than pure alumina. Temperature-programmed desorption of ammonia results illustrated that the addition of zirconia leads to an increase in the number of strong acid sites and the total number of acid sites compared with pure alumina. Thus, the spherical mesoporous ZrO2-Al2O3 composites prepared in this way were shown to be suitable for high temperature catalytic processes as a catalyst support.

Preparation and Characterization of Core-Shell γ-Fe<sub>2</sub>O<sub>3</sub>@SiO<sub>2</sub>@ Al<sub>2</sub>O<sub>3</sub> Magnetic Catalyst

Magnetic catalyst was made of magnetic core and surface coating layer and obtained a core-shell complex materials. The magnetic γ-Fe2O3 core has a relatively higher saturation magnetization, coercivity and good thermal stability even at 500°C. In order to prevent magnetic core forming spinel structure and migrating of Fe3+, a layer of silicon dioxide was coated by sol-gel method. During the process iron atoms scattered in –Si-O-Si- network and produced a γ-Fe2O3@SiO2 structure. Finally, the γ-Fe2O3@SiO2 powder was put into the alumina sol and evenly sprayed into a column of oil, after calcination the carrier of alumina layer was prepared.

On-line concentration sample stacking coupled with water-in-oil microemulsion electrokinetic chromatography

This study describes for the first time, the ability of a normal stacking mode (NSM) on-line concentration step coupled with water-in-oil (W/O) microemulsion electrokinetic chromatography (MEEKC), using six common penicillin antibiotics (oxacillin, penicillin V, penicillin G, nafcillin, ampicillin, and amoxicillin) as test analytes. Optimization of penicillin separation in the conventional W/O MEEKC system demonstrated that change in the type and concentration of the oil phase (1-butanol) and column temperature had a pronounced effect on the separation. With the subsequent development of the NSM coupled with W/O MEEKC, improved separation and detection sensitivities were observed when an organic solvent plug (1-propanol; 1.04 cm) was placed between the W/O microemulsion and the sample solutions. This could be attributed to the solution viscosity difference between the aqueous sample zone and the organic solvent plug causing the penicillin to be stacked in this 1-propanol plug. The optimal NSM W/O MEEKC provided about 12-fold increase in detection sensitivity compared with conventional sample injection (50 mbar, 3 s). Finally, this proposed method was successfully applied in the analyses of several food samples (porcine organs) spiked with penicillin.

Blowout in the Gulf: the BP oil spill disaster and the future of energy in America

On April 20, 2010, the gigantic drilling rig Deepwater Horizon blew up in the Gulf of Mexico, killing eleven crew members and causing a massive eruption of oil from BP's Macondo well. For months, oil gushed into the Gulf, spreading death and destruction. Americans watched real-time video of the huge column of oil and gas spewing from the obviously failed blowout preventer. What was missing, though, was the larger story of this disaster. In Blowout in the Gulf, energy experts William Freudenburg and Robert Gramling explain both the disaster and the decisions that led up to it. Blowout in the Gulf weaves a fascinating narrative of failures, missteps, and bad decisions, explaining why this oil spill was a disaster waiting to happen -- and how making better energy choices will help prevent others like it.

Origin and mechanism of the formation of the low-oil-saturation Moxizhuang field, Junggar Basin, China: Implication for petroleum exploration in basins having complex histories

The Moxizhuang field is a small oil field in the central Junggar Basin containing several low-saturation, low-resistivity oil reservoirs, which display a complex correlation between oil saturation and porosity and permeability that is atypical of both the filled and drained reservoirs. Biomarker associations of crude oil and grains containing oil inclusions (GOIs) of both the present-day water-bearing zones (water zones) and the oil- and water-bearing zones (low-oil-saturation pay zones) were analyzed to investigate the mechanisms for the formation of the low-saturation, low-resistivity oil accumulations. The biomarker assemblage and hierarchical cluster analysis indicate that oil in the Moxizhuang field was mostly generated from Permian source rock deposited in brackish to hypersaline anoxic environments. The pay zones and several water zones display GOI values as much as 38%, greater than the generally accepted threshold GOI value for an oil column (5%). These GOI values are similar to those for high-saturation oil reservoirs in the Bohai Bay Basin and oil zone samples from Australian basins, suggesting that both pay zones and water zones were high-saturation oil reservoirs in the geologic past. Geologic history analysis shows that the Moxizhuang field was located on the north wing of a paleoanticline during oil charge in the Late Cretaceous to Paleogene. This anticline has gradually evolved into a south-dipping monocline since the Neogene, causing northward remigration of accumulated oil. Differential lateral leakage of accumulated oil in different sandstone layers during the remigration phase led to the formation of the water zones with high GOI values (completely drained reservoirs) and the low-saturation, low-resistivity pay zones (partially preserved reservoirs) and caused the complex correlation between oil saturation and porosity and permeability. Compared with other postaccumulation physicochemical alteration processes, lateral leakage has rarely been recognized. Recognizing differential lateral leakage of accumulated petroleum with the existence of high-quality unfaulted cap rocks has important implication for petroleum exploration in sedimentary basins having complex evolution histories.

Wettability and Its Effects on Oil Recovery in Fractured and Conventional Reservoirs

Wettability, as the tendency of a reservoir rock surface to preferentially contact a particular fluid in a multiphase fluid system (Agbalaka et al., 2008), is determined by complex interface boundary conditions acting within the pore scale of porous media. Capillary pressure and relative permeability can be changed quite substantially from a wetting to a non-wetting phase, with subsequent influences on transition zone height, water–oil contacts, and residual oil saturation (Cockcroft et al., 1989). Wettability has a dominant effect on interface movement and associated displacement of different phases within porous media. For example, during tertiary miscible injection for a water-invaded oil column (double displacement process), gas and oil direct contact can be prevented by water surrounding residual oil due to wettability effects (water shielding phenomenon). Therefore, understanding formation wettability and its management is crucial for optimizing oil recovery. The wettability concept and its effect on multiphase flow within conventional and naturally fractured reservoirs (NFRs) is discussed here with some case studies.

Indonesian Fieldwide Application of Intelligent-Well Technology - A Case History

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21063, ’Indonesian Operator's First Fieldwide Application of Intelligent-Well Technology - A Case History,’ by Kim Sam Youl, and Harkomoyo, SPE, Kodeco Energy Company and Doug Finley, SPE, Halliburton, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. A fieldwide application of intelligent-well-completion technology was used in Indonesia to commingle “free energy” from an overlying gas cap to support production from underlying oil reservoirs that typically have a high water cut. Previously, wells in this offshore field were developed with conventional gas lift completions that used gas supplied from outside the platform. The application of an “auto-gas-lift” (AGL) concept, an intelligent-well technology, eliminated the capital equipment associated with conventional gas lift completions along with the conventional downhole gas lift equipment. Introduction The KE-38 field is in the East Java basin, approximately 30 miles off the northern coast of Madura Island, Indonesia (Fig. 1). Water depth averages approximately 190 ft in this block. The oil columns are between 60 and 300 ft thick, with a 500-ft-thick gas cap (on average) and an underlying water zone. True vertical depth of the gas/oil contact is 4,500 to 5,000 ft subsea. Porosity of the oil rim ranges from 18 to 26%, and permeability ranges from 20 to 100 md. The reservoir is normally pressured, and productivity ranges from 5 to 20 bbl/(psi-D). Maximum bottomhole pressure and temperature are 2,200 psi and 195°F, respectively. The oil is a slightly waxy, 35°API crude. Given that the reservoir fluid is nearly saturated, initial production from the wells was with natural flow. However, because the flowline pressure is high (approximately 900 psi), these wells would require artificial lift during the initial stage of operation to begin flow and maintain the gas/liquid ratio to optimize the produced-oil rate. Conventional gas lift completions have a setting-depth limitation relating to the gas lift mandrel. The maximum setting angle is less than 60°. However, an AGL interval-control valve (ICV) is capable of being set in any trajectory angle and can be set at the deepest point in the wellbore to optimize oil production. The AGL completion enables altering the flow characteristics of a zone without mechanical intervention.

A Gas-assisted Gravity Drainage Process in Naturally Fractured Reservoirs

Water alternating gas injection or simultaneous water and gas injection have been proposed as a good candidate to minimize gravity segregation and provide more efficient enhanced oil recovery performance in comparison to conventional continuous gas injection. However, water alternating gas-based processes can cause some difficulties with an increase in water saturation (e.g., water shielding) including diminished gas injectivity (Rao et al., 2004). As an effective alternative for water alternating gas injection, gas-assisted gravity drainage was developed for conventional reservoirs (U.S. Patent 2006/0289157) that takes advantage of the natural segregation of gas from liquid hydrocarbon during injection. The gas-assisted gravity drainage process consists of placing a horizontal well near the bottom of an oil column and injecting gas through existing vertical wells. Gravity segregation of injected gas will cause liquid hydrocarbon and water to drain down to the aforementioned horizontal well. Application of gas-assisted gravity drainage for enhanced oil recovery in a naturally fractured reservoir is evaluated in this article based on some facts and figures.

Analysis of Downhole Asphaltene Gradients in Oil Reservoirs with a New Bimodal Asphaltene Distribution Function

Downhole fluid analysis (DFA) has been successfully used to describe reservoir connectivity and fluid properties. DFA not only measures bulk fluid properties such as the gas−oil ratio (GOR), density, and light-end compositions of CO2, CH4, C2H6, C3H8−C5H12 fraction, and hexane and heavier (hexane +) fractions but also color (optical density) that is related to the heavy ends (asphaltenes and resins) in real time at downhole conditions. Therefore, color gradient analysis in oil columns becomes essential to determine reservoir complexities. In this paper, a new bimodal Γ-distribution function (asphaltene molecules + nanoaggregates and clusters) was proposed to characterize asphaltene components. A thermodynamic asphaltene-grading model was also developed to describe equilibrium distributions of heavy ends (heavy resins and asphaltenes) in oil columns using the multicomponent Flory−Huggins regular solution model coupled with a gravitational contribution. The variations of oil properties (such as molar volume, molar mass, solubility parameter, and density) with depth were calculated by the equation of state (EOS). The primary factors governing asphaltene distribution in reservoirs are the gravitational term, which is determined in part by the size of the asphaltene colloidal particle, and the solubility term, which is determined in large part by the GOR (composition). Consequently, it is critical to accurately measure both the fluid coloration and the GOR (composition) to understand the asphaltene gradient in oil columns. The results obtained in this work are in accordance with the Yen−Mullins model in asphaltene science. In particular, if asphaltenes are equilibrated in an oil reservoir, then a massive fluid flow through the reservoir had to have taken place, and permeable rocks are required, thereby implying connectivity, because asphaltenes necessarily enter the reservoir out of their ultimate equilibrium at the beginning of the reservoir charging. Therefore, a new powerful approach is established for conducting DFA color and GOR gradient analysis by coupling advanced asphaltene science with DFA technology (profiling of fluids) to address reservoir connectivity.

Economic Comparison of Intelligent Wells in Simultaneous Production of Oil and Gas Reserves From Single Wellbore

Summary Maximizing oil recovery in thin and ultrathin (less than 30 ft) oil columns is a challenge as a result of coning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal wells when bottom- or edgewater encroachment or invasion takes place. The development of the gas resources from these reservoirs is a major challenge because regulators want an optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to liquefied-natural-gas (LNG) projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral wells in simultaneous oil and gas development; the first (top) horizontal-lateral-well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second (lower) horizontal-lateral-well leg will be completed just above the gas/oil contact (GOC). Extensive numerical reservoir-flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoirs by providing a cost-effective-technology solution. The numerical-simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with a large gas cap compared with conventional wells and also provide the opportunity for automatic gas lift for low-gravity crude (°API). This paper (1) presents the use of intelligent multilateral wells to produce oil and gas from the same wellbore simultaneously in the thin oil reservoir and (2) provides information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoirs using intelligentwell technology, including cost effectiveness.

Pressure Build-up and Decay in Acid Gas Injection Operations in Reefs in the Zama Field, Canada, and Implications for CO2Storage

The objective of this paper is to examinereasons for pressure rise in the Zama X2X pool in northwestern Alberta, Canada, that was used foracid gas disposal, and whether subsequent pressure decay was a result of pressure dissipation into a larger aquifer. The Zama X2X pool, approximately 1 km2 in size, is connected to four other nearby poolsthrough a common underlying aquifer. Pressure analysis for all the pools indicates that they are in goodhydraulic communication. Initial pressure in the Zama X2X pool was approximately 15 MPa. Pressuredeclined first during oil production, stabilizing at around 10 MPa in the early 1970s, after which started toincrease such that it reached 26 MPa in 1986. Subsequently, pressure declined reaching 22 MPa by 1995just prior to starting injection of acid gas (80% CO2 and 20% H2 S). The operator injected acid gas at lowerrates and wellhead pressures than those licensed by the regulatory agency. Despite significant production ofwater and hydrocarbons, the pressure in the Zama X2X pool continued to be higher than the initial reservoirpressure by more than 5 MPa, such that disposal operations were suspended in late 1998. Oil productioncontinued all this time until 2002. Numerical simulations using CMG-IMEXTM and corresponding sensitivity studies reported in this papershow that disposal of more than 1 million m3 of water between 1970 and 1988 and again in 1992-1993 inthe adjacent Zama YY pool, which is in good hydrodynamic communication with the Zama X2X poolthrough the aquifer below the oil column, is the main reason for the high pressures observed in the ZamaX2X pool. Sensitivity studies indicate that pressure decay in the X2X pool was due to fluid production.The study indicates that while pressure rise has been caused by hydraulic communication between theX2X and YY pools through the common aquifer, the aquifer was not of large volume to allow dissipationof the pressure. In addition to the case study, the implications of pressure communication to geological storage of CO2 in aquifers are briefly discussed.

Hydrocarbon charge in the onshore Canning Basin: insights from quantitative fluorescence and fluid inclusion investigations

The vast and mostly onshore Canning Basin—with an area of approximately 595,000 m2—is the least explored onshore sedimentary basin in Australia. As part of the petroleum system assessment carried out by WA DMP, more than 160 samples were investigated from eight wells in the onshore Canning Basin—they are: Acacia-1 Dodonea-1 Dodonea-2 Lake Hevern-1 Looma-1 White Hill-1 Wilson Cliffs-1 Yulleroo-1. Fluid inclusion and quantitative fluorescence techniques developed by CSIRO were used, including: The grains containing oil inclusions (GOITM) technique; The quantitative grain fluorescence (QGF) technique; QGF on extracts (QGF-E); and, the total scanning fluorescence (TSF) technique. The results reveal a widespread occurrence of hydrocarbon shows in the reservoir intervals investigated—7–8 wells showed evidence of oil migration and/or accumulations often occurring at multiple depth intervals. In White Hill-1, elevated QGF and QGF-E responses were recorded in the sandy units in a depth interval of more than 500 m in the Fairfield Group. A residual or palaeo oil column of >20 m gross height at 1,655 m was apparent from the QGF and QGF-E depth profiles—and GOI and TSF data. Oil inclusions from the Fairfield Group in White Hill-1 show spectral signature typical of thermally mature and light-medium API gravity. The TSF results also indicate the presence of some condensate species, as well as relatively heavy and possibly bio-degraded oils. The new fluid inclusion and fluorescence data provide direct evidence of an active petroleum system in the Canning Basin at multiple reservoir intervals, which may be of local significant quantity.

New exploration opportunities in the offshore northern Perth Basin

The petroleum prospectivity of the northern Perth Basin has been assessed by Geoscience Australia (GA) as part of the Australian Government’s Offshore Energy Security Program, in support of the 2011 offshore acreage release. This assessment includes the first published synthesis of data from fourteen new field wildcat wells drilled in this part of the basin since the Cliff Head 1 discovery (2001), and the interpretation of new regional 2D seismic data acquired during GA survey 310. Most petroleum accumulations in the northern Perth Basin are associated with Permian and Triassic source and reservoir intervals, and are found onshore and nearshore (ie. Cliff Head, Frankland, Dunsborough and Perseverance discoveries). In addition to the technical and commercial successes, numerous wells in the offshore part of the basin have intersected residual oil columns indicative of trap breach. New and legacy palynological data from Permian to Cretaceous strata in offshore wells have been used to provide age constraints for a sequence stratigraphic framework for this part of the basin. New seismic data show Permo-Triassic strata that are stratigraphic equivalents of the productive onshore and nearshore Perth Basin petroleum system, also occur within Permian half-graben in the outer Abrolhos and Houtman sub-basins. Source rock, oil stain and fluid inclusion sampling from this interval suggest that the proven onshore petroleum system is also effective in the offshore. A refined tectono-stratigraphic model for the offshore basin provides insights into basin evolution, prospectivity and contributing factors driving trap breach. Geochemical sampling in the context of the new detailed sequence framework, including from recently dredged rock samples from incised canyons, has also provided insight into the potential effectiveness of a Jurassic/Cretaceous petroleum system in the Houtman and Zeewyck sub-basins.

Preparation and properties of magnetic alumina microspheres with a γ-Fe 2O 3/SiO 2 core and Al 2O 3 shell

Abstract Magnetic alumina composite microspheres with γ-Fe 2O 3 core/Al 2O 3 shell structure were prepared by the oil column method. A dense silica layer was deposited on the surface of γ-Fe 2O 3 particles (denoted as γ-Fe 2O 3/SiO 2) with a desired thickness to protect the iron oxide core against acidic or high temperature conditions. γ-Fe 2O 3/SiO 2/Al 2O 3 particles with about 85 wt% Al 2O 3 were obtained and showed to be suitable for practical applications as a magnetic catalyst or catalyst support due to their magnetic properties and pore structure. The products were characterized with scanning electron microscope (SEM) and transmission electron microscope (TEM), nitrogen adsorption-desorption, and vibrating sample magnetometer (VSM). The specific surface area and pore volume of the γ-Fe 2O 3/SiO 2/Al 2O 3 composite microspheres calcined at 500 °C were 200 m 2/g and 0.77 cm 3/g, respectively.

Equation-of-State-Based Downhole Fluid Characterization

Summary Downhole fluid analysis (DFA), together with focused-sampling techniques and wireline-formation-tester (WFT) tools, provides real-time measurements of reservoir-fluid properties such as the compositions of four or five hydrocarbon components/groups and gas/oil ratio (GOR). With the introduction of a new generation of DFA tools that analyze fluids at downhole conditions, the accuracy and reliability of the DFA measurements are improved significantly. Furthermore, downhole measurements of live-fluid densities are integrated into the new tools. Direct pressure and temperature measurements of the flowline ensure capture of accurate fluid conditions. To enhance these advanced features further, a new method of downhole fluid characterization based on the equation-of-state (EOS) approach is proposed in this work. The motivation for this work is to develop a new approach to maximize the value of DFA data, perform quality assurance or quality control of DFA data, and establish a fluid model for DFA log predictions along with DFA fluid profiling. The basic inputs from DFA measurements are weight percentages of CO2, C1, C2, C3–C5 and C6+, along with live-fluid density and viscosity. A new method was developed in this work to delump and characterize the DFA measurements of C3–C5 (or C2–C5) and C6+ into full-length compositional data. The full-length compositional data predicted by the new method were compared with the laboratory-measured gas chromatograph data up to C30+ for more than 1,000 fluids, including heavy oil, conventional black oil, volatile oil, rich gas condensate, lean gas condensate, and wet gas. These fluids have a GOR range of 8–140,000 scf/STB and a gravity range from 9 to 50°API. A good agreement was achieved between the delumped and gas-chromatograph compositions. In addition, on the basis of the delumped and characterized full-length compositional data, EOS models were established that can be applied to predict fluid-phase behavior and physical properties by virtue of DFA data as inputs. The EOS predictions were validated and compared with the laboratory-measured pressure/volume/temperature (PVT) properties for more than 1,000 fluids. The GOR, formation-volume factor, density, and viscosity predictions were in good agreement with the laboratory measurements. The established EOS model then was able to predict other PVT properties, and the results were compared with the laboratory measurements in good agreement. Consequently, the established EOS models have laid a solid foundation for DFA log predictions in DFA fluid profiling, which has been integrated successfully with DFA measurements in real time to delineate compositional and asphaltene gradients in oil columns and to determine reservoir connectivity. The latter results are beyond the scope of this work and have been given in separate technical papers.

Formation evaluation of an onshore appraisal well ‘KG-5’, “green field”, Niger Delta, Nigeria

The Well KG-5 is a vertical well drilled to evaluate an exploration prospect in the onshore “Green Field” Niger Delta. It discovered a significant oil column within the sandstone reservoir intervals. A conventional suite of wireline logs including gamma ray, calliper, sonic, density, neutron, dual laterolog and micro-SFL resistivities were acquired for formation evaluation purposes. Also two cores were cut in the reservoir interval for hydrocarbon shows analysis. The result of the formation evaluation shows that reservoir zones Q-A and Q-B contain oil while reservoirs Q-C and Q-D are water filled. The contact between the oil and water (Oil water contact-OWC/Free Water Level) is at a depth of 2464m. The net pay porosity values range between 0.139v/v and 0.165v/v with an average of about 0.158v/v. The trends of the neutron-density crossplot and the Picket plot indicate that there is a little contribution of dispersed and laminated clays in the reservoir, which would have significantly affected the poro-perm values of the reservoir intervals. Also, the net pay water saturation (0.266v/v) is reduced as compared with the net reservoir saturation (0.434v/v). And out of 8.080 equivalent pore column (EPC), 5.935 are equivalent hydrocarbon column (EHC). Because the minor claystone beds within the reservoir sands are laterally continuous and may be vertical permeability barriers; the reservoir engineers should run a separate perforation for reservoirs Q-A and Q-B. This is because the two reservoirs may not be in vertical communication due to claystone baffles. And so hydrocarbon flow would be mainly horizontal.

Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well. Introduction The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers. These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures. Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery. An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field. Planning Phase The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.

Catalytic hydrogenation of ethylanthraquinone over highly dispersed eggshell Pd/SiO 2–Al 2O 3 spherical catalysts

Spherical Al 2O 3 and SiO 2–Al 2O 3 supports with different silica contents have been synthesized by the oil column method. After impregnation with Na 2PdCl 4 solution and subsequent calcination, PdO/Al 2O 3 and PdO/SiO 2–Al 2O 3 catalyst precursors were obtained. X-ray powder diffraction and low temperature N 2 adsorption–desorption measurements showed that the addition of silica increased the thermal stability, surface acidity, specific surface area and total pore volume of the spherical alumina. Temperature programmed reduction and H 2–O 2 titration indicated that Pd supported on the SiO 2–Al 2O 3 spheres possessed higher dispersion and smaller particle size than that supported on pristine spherical Al 2O 3. Catalytic hydrogenation of ethylanthraquinone using molecular hydrogen was studied over the reduced Pd/Al 2O 3 and Pd/SiO 2–Al 2O 3 catalysts with different silica contents. Under identical reaction conditions, the reaction activity and stability increased with increasing silica content.