The Experts below are selected from a list of 140373 Experts worldwide ranked by ideXlab platform
Keir Becker - One of the best experts on this subject based on the ideXlab platform.
-
Borehole observations of Fluid flow from South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc
Earth and Planetary Science Letters, 2007Co-Authors: C. Geoffrey Wheat, Patricia Fryer, Andrew T. Fisher, Samuel Hulme, Hans W. Jannasch, Michael J. Mottl, Keir BeckerAbstract:Abstract A sealed borehole observatory (CORK) was deployed on South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc to explore subduction-related processes on a non-accretionary, convergent plate margin. Formation Fluid was overpressured relative to ambient hydrostatic conditions. Fluid flowed from the borehole at ~ 0.2 L/s when the observatory was opened to recover instruments 2 yr after it was installed. The chemical composition of the Formation Fluid is similar to that extrapolated from trends in pore water data collected during Ocean Drilling Program Leg 195 when the observatory was established. Reduced sulfur is present in this highly-alkaline (pH 12.4) Formation Fluid, indicative of microbial activity at or below the depth of the screened casing, 149–202 m below the seafloor. Discharge from the open borehole continued for 37 days, until the observatory was resealed. This discharge requires significant permeability at depth (> 6 × 10− 14 m2). Zones of high permeability may be associated with the Formation of headwall scarps, consistent with numerous slumps on the southeastern flank of the seamount, and likely shape a geochemical environment suitable for an active microbial community.
C. Geoffrey Wheat - One of the best experts on this subject based on the ideXlab platform.
-
Borehole observations of Fluid flow from South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc
Earth and Planetary Science Letters, 2007Co-Authors: C. Geoffrey Wheat, Patricia Fryer, Andrew T. Fisher, Samuel Hulme, Hans W. Jannasch, Michael J. Mottl, Keir BeckerAbstract:Abstract A sealed borehole observatory (CORK) was deployed on South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc to explore subduction-related processes on a non-accretionary, convergent plate margin. Formation Fluid was overpressured relative to ambient hydrostatic conditions. Fluid flowed from the borehole at ~ 0.2 L/s when the observatory was opened to recover instruments 2 yr after it was installed. The chemical composition of the Formation Fluid is similar to that extrapolated from trends in pore water data collected during Ocean Drilling Program Leg 195 when the observatory was established. Reduced sulfur is present in this highly-alkaline (pH 12.4) Formation Fluid, indicative of microbial activity at or below the depth of the screened casing, 149–202 m below the seafloor. Discharge from the open borehole continued for 37 days, until the observatory was resealed. This discharge requires significant permeability at depth (> 6 × 10− 14 m2). Zones of high permeability may be associated with the Formation of headwall scarps, consistent with numerous slumps on the southeastern flank of the seamount, and likely shape a geochemical environment suitable for an active microbial community.
Sebastian Bauer - One of the best experts on this subject based on the ideXlab platform.
-
A unified phase equilibrium model for hydrogen solubility and solution density
International Journal of Hydrogen Energy, 2018Co-Authors: Christof Beyer, Sebastian BauerAbstract:Abstract For the transition to a clean and sustainable energy production from renewable sources like solar or wind power, large and secure storage of energy is required to compensate for the intermittent nature of these sources. Hydrogen could be a suitable energy carrier and hydrogen geological storage could provide the large capacities required. During storage hydrogen will be brought in contact with the Formation Fluids present, resulting in dissolution and possibly inducing geochemical reactions. Therefore in this work an accurate, consistent and reliable hydrogen solubility model is established, which allows to calculate the hydrogen solubility in the Formation Fluid and the corresponding variation of Fluid density. The model accounts for system pressure, temperature and Formation Fluid salinity as well as the molar fraction, fugacity coefficient, Henry's constant, Poynting factor and activity coefficient of hydrogen. In the range of typical hydrogen geological storage conditions of 273–373 K, 1–50 MPa and 0–5 mol/kg NaCl this model can reproduce all available experimental data and predict hydrogen solubility in the Formation Fluid and the Formation Fluid density accurately. The model can predict hydrogen solubility within a maximum relative error of 5% for pure water and 15% for brines within the salinity range considered, which is in the range of uncertainty of measurement data. For realistic hydrogen gas geological storage, the model is extended to represent also H 2 -N 2 or H 2 -CH 4 mixed gas systems as well as mixed electrolyte solutions containing Na, K, Ca, Mg, Cl or SO 4 and combinations of those. Model derivation, model calculations and implementation as well as an application example are presented to demonstrate the applicability of the developed methods and the model.
Hani Elshahawi - One of the best experts on this subject based on the ideXlab platform.
-
Downhole Measurement of Methane Content and GOR in Formation Fluid Samples
SPE Reservoir Evaluation & Engineering, 2006Co-Authors: Chengli Dong, Peter S. Hegeman, Andrew J.g. Carnegie, Hani ElshahawiAbstract:Summary Formation Fluid sampling early in the life of a well ensures that vital inFormation is available for timely input to field planning decisions. For example, in subsea wells, flow assurance is a major concern, and Formation Fluid samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a Formation Fluid sample is taken from a well drilled with oil-based mud (OBM), sample contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample pressure/volume/temperature (PVT) properties. A technique of monitoring sample contamination from OBM filtrate uses optical means to monitor the buildup of both color- and methane-absorption signals during sampling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and lightly colored crude oils; for such Fluids, the color buildup becomes difficult to detect, but the high methane content of these Fluids makes possible a reliable methane-based OBM-contamination monitoring algorithm. Gas/oil ratio (GOR) is an important property of crude oil, and it is a vital input to the design of production facilities. Conventionally, GOR is measured at a PVT laboratory, and it may take many weeks before the laboratory can provide this critical inFormation. In this paper, we describe the development of an in-situ GOR measurement technique, which uses the optical properties of methane and oil components in crude oil. With this technique, GOR can be measured downhole in real time, when the sample is taken, and without requiring phase separation. Downhole GOR has many advantages over the conventional GOR measurement techniques. It does not require tampering with the sample, which helps the operator maintain the Fluid in a single phase during and after sampling. It also can aid in fingerprinting oils from different layers and provides early indications of GOR that can be compared to PVT lab results. Both the OBM contamination monitoring and the GOR algorithms work well for most crude oils. However, for heavy (dark) oils, the contamination prediction from the methane component and the GOR prediction become unreliable because of the color effect. In this paper, we describe the methodology for downhole GOR measurement, and we provide details of a decolorization technique to remove the color effect of dark oils from the methane, oil, and base channels in a downhole optical Fluid analyzer tool. This technique significantly improves real-time contamination monitoring and GOR prediction results for dark oils. Introduction Real-time estimation of sample contamination by drilling-mud filtrate is critical for the collection of representative hydrocarbon-Fluid samples in wells drilled with OBM. The hydrocarbon sample may become useless if the contamination is too high (typically above 10 to 15% for crude oils or 1 to 3% for gas condensates). In-situ sample OBM contamination can be predicted in real time by a downhole optical Fluid analyzer tool, which is used as a module of a Formation testing tool (Mullins and Schroer 2000; Smits et al. 1995; and Crombie et al. 1998). This is accomplished by using a technique of monitoring OBM contamination, which is based on measuring the change of methane content and color in the flowline as cleanup with the downhole pump proceeds and progressively larger fractions of Formation Fluid replace the OBM filtrate. An accurate value of the GOR is important for many applications, including crude-oil typing and production facilities design. Conventionally, GOR is measured in a PVT laboratory by flashing the crude oil and then measuring the volumes of the gaseous and liquid phases at standard conditions (1 atm and 60°F). It may take many weeks before the laboratory can provide this critical inFormation. The downhole optical Fluid analyzer tool has a methane channel and an oil channel, which cover the methane absorption peak and oil absorption peak, respectively. We have developed an in-situ GOR measurement technique that derives GOR from the optical density (OD) ratio of the methane channel and the oil channel. Thus, GOR can be measured downhole in real time, when the sample is taken, and while keeping the sample intact. Downhole GOR is valuable in providing an early confirmation check for subsequent laboratory PVT analysis. The downhole GOR measurement also aids fingerprinting oils from different layers and helps the operator maintain the Fluid in a single phase during sampling. Both the OBM contamination monitoring and the downhole GOR techniques work well for the majority of light- to medium-colored crude oils. However, when these two techniques are applied to heavy oils, the color absorption of the crude extends to the near-infrared region (NIR) and covers the methane and oil molecular-vibration peaks. If not corrected for, this would result in errors in the methane-based contamination prediction and GOR prediction. This paper describes a decolorization algorithm to remove the color effect from the methane and the oil channels. This algorithm is based on the exponential decay of color absorption toward the longer wavelengths in the NIR region. After decolorization, the methane and oil channels contain only the molecular-vibration absorptions of methane and oil, which are then used to derive an accurate crude-oil contamination value and GOR. The examples described here involved OBM. It should be noted that all the techniques for GOR calculation mentioned in this paper can be, and have been, applied successfully to sampling in wells drilled with water-based mud.
-
Accurate Measurement of the Hydrogen Sulfide Content in Formation Fluid Samples-Case Studies
All Days, 2005Co-Authors: Hani Elshahawi, Mohamed HashemAbstract:Abstract The Hydrogen Sulfide (H2S) content of subsurface hydrocarbon reservoirs has a profound impact on completion, surface production, and process design. The H2S content of crude oil directly impacts the sale value of the produced hydrocarbons, while the H2S content of produced water can result in significant production problems, which can lead to detrimental effects on hydrocarbon transport and sales specifications. In theory, the H2S content of reservoir Fluids can be determined from samples collected by wireline Formation tester tools. In practice, however, measurement is complicated by the partial-to-total loss of the gas by absorption/adsorption onto the metal components of the downhole tool, storage bottles, and transfer/analysis system, particularly those made from iron. H2S readily forms non-volatile and insoluble metal sulphides by reaction with many other metals and metal oxides, and analysis of the Fluid samples can therefore underestimate the true H2S content. Therefore, many practical challenges must be overcome to accurately determine H2S levels in Formation tester samples. These include metallurgical design considerations, sampling environment and system selection as well as the timing and type of H2S analyses. This paper details our successes in accurately measuring both high and low concentrations of H2S in downhole Formation tester samples. It describes an integrated workflow by which ultra low H2S concentrations can be captured and preserved in Formation tester samples until the tool is brought back to surface where the samples can be analyzed. This workflow includes a number of modifications to some commercial Formation tester tools and sample chambers to ensure that the bulk of the H2S does not get absorbed by the time the tool arrives to the surface. Downhole measurements made close to the Fluid entry into the sampling tool are used to cross check and verify the surface measurements. Finally, on surface, a number of techniques are used to measure H2S concentration in the sample bottles as soon as practical after the Formation tester tool is brought to the surface. The paper demonstrates, through a number of case studies, that by following this comprehensive workflow, it is possible to capture and analyze hydrocarbon samples with minimal loss of H2S, regardless of the levels of H2S being measured. Introduction The presence of Hydrogen Sulfide (H2S) in the reservoir Fluid has a major effect on project economics as well as occupational health, safety, and environment (HSE). The accurate measurement of H2S concentrations in the reservoir Fluids is critical to the design of completion, surface, and production facilities. With accurate determination of H2S levels in the subsurface, the operator can hope to:Determine which (if any) HSE measures must be implemented for dealing with H2S at the various stages of exploration, appraisal, development, production, and abandonment of a given prospect.Indicate the need for special metallurgical or process design to deal with certain levels of H2S in the presence of various other mitigating or accentuating factors.Detect the onset and evolution of reservoir souring upon the implementation of water injection or other enhanced recovery techniques. The measurement of H2S concentrations in samples collected by Formation testers is complicated by the partial-to-total loss of the gas by reaction of the metal components and the drilling/completion Fluids. Many practical challenges must be overcome to accurately determine H2S levels in Formation tester samples. These include metallurgical design considerations, sampling environment and system selection as well as the timing and type of H2S analyses required.
-
In-situ characterization of Formation-Fluid samples: Case studies
Journal of Petroleum Technology, 2005Co-Authors: Hani Elshahawi, Peter S. Hegeman, Go Fujisawa, C. Dong, Oliver C. Mullins, Mohamed Hashem, S. BetancourtAbstract:Fluid sampling in the early stages of exploration and development provides key inFormation for field planning and facilities design. In many deepwater and other high-cost wells, Formation-tester samples may be the only reliable source of Fluid properties for economic screening. Real-time in-situ Fluid characterization can ensure sample quality and optimize the sampling process. Techniques for downhole Fluid characterization include real-time composition measurement, Fluid-type identification, and single-phase assurance.
-
Insitu Characterization of Formation Fluid Samples - Case Studies
All Days, 2004Co-Authors: Hani Elshahawi, Go Fujisawa, C. Dong, Oliver C. Mullins, Mohamed Hashem, P. Hegeman, S. BetancourtAbstract:Fluid sampling in the early stages of exploration and development provides key inFormation for field planning and facilities design. In many deepwater and other high-cost wells, Formation-tester samples may be the only reliable source of Fluid properties for economic screening. Real-time in-situ Fluid characterization can ensure sample quality and optimize the sampling process. Techniques for downhole Fluid characterization include real-time composition measurement, Fluid-type identification, and single-phase assurance.
-
Downhole Measurement of Methane Content and GOR in Formation Fluid Samples
All Days, 2003Co-Authors: Chengli Dong, Peter S. Hegeman, Andrew Carnegie, Hani ElshahawiAbstract:Abstract Formation Fluid sampling early in the life of a well ensures that vital inFormation is available for timely input to field planning decisions. For example, in subsea wells, flow assurance is a major concern, and Formation Fluid samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a Formation Fluid sample is taken from a well drilled with Oil-Base Mud (OBM), the sample contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample PVT properties. The Oil-Base Contamination Monitoring (OCM) technique uses optical means to monitor the buildup of both color and methane absorption signals during sampling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and for lightly colored crude oils; for such Fluids, the color buildup becomes difficult to detect, but the high methane content of these Fluids makes possible a reliable methane-based OCM algorithm. Gas/Oil Ratio (GOR) is an important property of crude oil, which has profound value in the design of production facilities. Conventionally, GOR is measured at a PVT lab and may take many weeks before the lab can provide this critical inFormation. In this paper, we describe the development of an in-situ GOR measurement technique, which uses the optical properties of methane and oil components in crude oil. With this technique, GOR can be measured downhole in real time, when the sample is taken and without requiring phase separation. Downhole GOR has many advantages over the conventional wellsite GOR measurement techniques. It does not require tampering with the sample, which helps the operator maintain the Fluid in a single-phase during and after sampling. It can also aid in fingerprinting oils from different layers and provides early indications of GOR that can be compared to PVT lab results. Both the OCM and the GOR algorithms work well for most crude oils. However, for dark oils, the contamination prediction from methane component and the GOR prediction become unreliable because of the color effect. In this paper, we describe the methodology for downhole GOR measurement and we provide details of a decolorization technique which we have recently developed to remove the color effect of dark oils from the methane, oil and base channels in the LFA* Live Fluid Analyzer tool. This technique significantly improves real-time contamination monitoring and GOR prediction results for dark oils. Introduction Real-time estimation of sample contamination by drilling mud filtrate is critical for the collection of representative hydrocarbon Fluid samples in wells drilled with Oil-Base Mud (OBM). The hydrocarbon sample may become useless if the contamination is too high (typically above 10–15% for crude oils or 1–3% for gas condensates). In-situ sample OBM contamination can be predicted in real time by Live Fluid Analyzer (LFA)1,2, a module of the Modular Dynamics Tester3 MDT* Formation tester tool. This is accomplished by using the OCM* OBM Contamination Monitoring technique. This technique is based on measuring the change of methane content and color in the flow line as cleanup with the downhole pump proceeds and progressively larger fractions of Formation Fluid replace the OBM filtrate.
Michael J. Mottl - One of the best experts on this subject based on the ideXlab platform.
-
Borehole observations of Fluid flow from South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc
Earth and Planetary Science Letters, 2007Co-Authors: C. Geoffrey Wheat, Patricia Fryer, Andrew T. Fisher, Samuel Hulme, Hans W. Jannasch, Michael J. Mottl, Keir BeckerAbstract:Abstract A sealed borehole observatory (CORK) was deployed on South Chamorro Seamount, an active serpentinite mud volcano in the Mariana forearc to explore subduction-related processes on a non-accretionary, convergent plate margin. Formation Fluid was overpressured relative to ambient hydrostatic conditions. Fluid flowed from the borehole at ~ 0.2 L/s when the observatory was opened to recover instruments 2 yr after it was installed. The chemical composition of the Formation Fluid is similar to that extrapolated from trends in pore water data collected during Ocean Drilling Program Leg 195 when the observatory was established. Reduced sulfur is present in this highly-alkaline (pH 12.4) Formation Fluid, indicative of microbial activity at or below the depth of the screened casing, 149–202 m below the seafloor. Discharge from the open borehole continued for 37 days, until the observatory was resealed. This discharge requires significant permeability at depth (> 6 × 10− 14 m2). Zones of high permeability may be associated with the Formation of headwall scarps, consistent with numerous slumps on the southeastern flank of the seamount, and likely shape a geochemical environment suitable for an active microbial community.