Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Facilities Design, Construction and Operation
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Supported Catalyst Regeneration and Reuse for Upgrading of Athabasca Bitumen in Conjunction With In-Situ Combustion
Abu, Ibrahim I. (University of Calgary) | Moore, R. Gordon (University of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Ursenbach, Matthew G. (University of Calgary) | Mallory, Donald G. (University of Calgary) | Pereira-Almao, Pedro (University of Calgary) | Scott, Carlos E. (University of Calgary) | Carbognani Ortega, Lante (University of Calgary)
Summary A commercial supported catalyst was regenerated and reused for three combustion-tube tests to study the upgrading potential of Athabasca bitumen supplied by Japan Canada Oil Sand Ltd. (JACOS). These tests were part of a larger program of combustion-tube tests performed by the In-Situ Combustion Research Group (ISCRG) under the auspices of the Alberta Ingenuity Center for In-Situ Energy (AICISE). The tests were premixed and carried out at the same pressure of 3.45 mPa (500 psi), preheat temperature (95°C), and ignition temperature (350°C). Test 1 used a fresh supported catalyst. Test 2 used a regenerated catalyst retrieved from Test 1, and Test 3 used regenerated catalysts (second time regeneration of catalysts from Test 1) retrieved from Test 2. Significant hydrodenitrogenation (HDN), 52% for the fresh catalyst Test 1, 38.1% for regenerated catalyst Test 2 and 23.8% for regenerated catalyst Test 3, was obtained. The levels of hydrodesulfurisation (HDS) obtained were 18.1, 18.4, and 15.2% for Tests 1, 2, and 3, respectively. The significant HDN and HDS removal coupled with decreased viscosity, increased °API value, and light hydrocarbons indicate upgrading of the original Athabasca bitumen for all three tests. The results showed that although the regenerated catalyst Tests 2 and 3 lost HDN activity compared to the fresh catalyst, the regenerated catalysts were still active for repeated use for in-situ upgrading.
- Personal (0.46)
- Research Report > New Finding (0.34)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Summary Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone. Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure. An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process. The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage. In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer. Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Wabiskaw Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.94)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Biotreatment of Hydrate-Inhibitor-Containing Produced Waters at Low pH
Janson, Arnold (ConocoPhillips Global Water Sustainability Center) | Santos, Ana (ConocoPhillips Global Water Sustainability Center) | Hussain, Altaf (ConocoPhillips Global Water Sustainability Center) | Judd, Simon (Qatar University/Cranfield University) | Soares, Ana (Cranfield University) | Adham, Samer (ConocoPhillips Global Water Sustainability Center)
Summary With proper treatment to remove organics and inorganics, one can use the produced water (PW) generated during oil-and-gas extraction as process water. Biotreatment is generally regarded as the most cost-effective method for organics removal, and although widely used in industrial wastewater treatment, PW biotreatment installations are limited. This paper follows up to an earlier paper published in the SPE Journal (Janson et al. 2014). Although the earlier paper assessed the biotreatability of PW from a Qatari gas field from the summer season, this paper focuses on assessing the biotreatability of PW during the winter season [i.e., containing the thermodynamic hydrate inhibitor monoethylene glycol (MEG) and a kinetic hydrate inhibitor (KHI)]. Tests were conducted in batch and continuous reactors under aerobic mixed-culture conditions without pH control during 31 weeks. The results indicated that one could remove >80% of the chemical oxygen demand (COD) and total organic carbon (TOC) through biological treatment of PW with 1.5% MEG added. In contrast, biotreatment can remove only ≈43% of COD and TOC present in PW when 1.5% KHI was added as a hydrate inhibitor; 2-butoxyethanol, a solvent in KHI, is extremely biodegradable; it was reduced in concentration from >5000 to <10 mg/L by biotreatment; the KHI polymer though was only partially biodegradable. Cloudpoint tests conducted on PW with 1.5% KHI added showed only an 8°C increase in cloudpoint temperature (from 35 to 43°C). The target cloudpoint temperature of >60°C was not achieved. Although the feed to the reactors (PW with either KHI or MEG) was at pH 4.5, the reactors stabilized at a pH of 2.6, considered extremely acidic for aerobic bioactivity. The successful operation of an aerobic biological process for an extended period of time at a pH of 2.6 was unexpected, and published reports of bioactivity at that pH are limited. After extensive analytical tests, it was concluded that the pH decrease was caused by the production of an inorganic acid. A mechanism by which hydrochloric acid could be produced biologically was proposed; however, further research in this area by the academic community is recommended.
- North America > United States (0.93)
- Asia > Middle East > Qatar (0.15)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.89)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Facilities Design, Construction and Operation (1.00)
Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.
- North America > United States > Texas (1.00)
- Asia (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock (0.34)
- North America > United States > Texas > Permian Basin > Midland Basin > Snyder Field (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Two Freds Field (0.99)
- North America > United States > Louisiana > Little Creek Field (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (3 more...)
Modeling the Impact of Corrosion on Well Integrity for Offshore Wells
Narhi, Ward (ExxonMobil Upstream Research Company) | Kibey, Sandeep (ExxonMobil Upstream Research Company) | Kent, David (ExxonMobil Upstream Research Company) | Aylor, Adam (ExxonMobil Development Company) | Abdulhai, Walid M. (Zakum Development Company) | Lam, Gan Chee (Zakum Development Company) | Khemakhem, A. S. David (Zakum Development Company)
Abstract Structural integrity of casings is critical for safe and economic operation of offshore wells and it can be compromised by external corrosion due to exposure to environment such as seawater. Assessing the impact of severe casing corrosion on the structural integrity of the well can be challenging due to complexities arising from local wall loss, non-uniform wall thickness, presence of holes due to severe corrosion, and non-bonded cement. Such complexities are not adequately addressed by existing codes/standards and available analytical equations. This paper presents a study that utilized a combination of a thermo-mechanical well simulator and threedimensional (3D) finite element analysis (FEA) to model severely corroded offshore well casing strings towards assessing structural integrity of the wells. The goal of the study was to determine the extent of allowable corrosion in conductor and surface casing beyond which the wells would be at risk for failure, and if topping off the cement in the annulus would be beneficial for structural integrity. A thermo-mechanical well simulator was utilized to model how corrosion wall loss evolved over time for both the conductor and surface casing, and the corresponding impact on their load capacity. In conjunction with the well simulator, full 3D FEA was conducted to model various complexities, such as the effect of corrosion holes and non-uniform corrosion. The 3D FEA helped assess the impact of remedial cementing on casing integrity and refine the critical wall thickness limit needed to withstand loads predicted by the well simulator. Compression and buckling were identified as governing failure modes and FEA results were compared with a buckled conductor in the field. The systematic, mechanics-based approach used in this study provided a basis for risk assessment where at-risk wells can be prioritized for remediation and/or abandonment.
- Asia > Middle East (0.46)
- North America > United States (0.28)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract Turbomachinery for oil and gas EPC projects are shop tested to minimize the plant start-up risks and assure a trouble-free operation. However the extent of testing of turbomachinery vary with each project, though the minimum requirements dictated by the international codes and standards shall be met. In fact testing activities for turbomachinery are expensive, and specifying additional tests on top of the minimum requirements; which are narrated in this paper for major turbomachinery, need to be technically and commercially justified. Defining the extent of testing depends on several key factors which are listed and illustrated in this article. The Owner; in collaboration with the Contractor, is responsible to approve the required tests for a certain equipment based on critical analysis and a trade-off between risk, cost and schedule. However manufacturers' testing capacities do not always meet the testing requirements, this needs to be considered when specifying tests, else a test bed upgrade is necessary if the Owner is ready to contribute to the cost. This article surfs through the topic of shop testing for turbomachinery presenting best practices and lessons learnt from recent oil & gas EPC projects.
- Facilities Design, Construction and Operation > Processing Systems and Design > Compressors, engines and turbines (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (0.94)
- Management > Strategic Planning and Management > Project management (0.82)
- (3 more...)
Abstract The objective of this paper is to present Remote Sensing technologies and methodologies developed within Total to detect Oil Slicks and to ensure spill response in the offshore domain. –In the case of incidents occurring on surface/subsurface facilities operated by Total or nearby facilities operated by others. –For regular monitoring of offshore production facilities. –Research concerning new emerging technologies in the remote sensing area is also dicussed. Several actual field cases are presented (seeps, spills, boat sewages). In the offshore domain, the majority of satellite data used for hydrocarbon detection consists of radar (SAR – Synthetic aperture radar) images. Because of constraints essentially due to meteorological conditions (important cloud cover….), the programming of radar data, from medium to low resolution, is favored to optical data, especially as the existence of radar constellations offers the opportunity to acquire an images everyday anywhere in the world. The ‘critical' point still remains the programming delay, which is the elapsed time before the collection of the first image acquired on the zone of interest. This delay is fixed by the technical specificities of each SAR satellite, the orbits trajectories, the localization of the area of interest (there are more daily acquisition opportunities at the poles than at the equator), the radar systems depointing capabilities (angles of shots…)
- Health, Safety, Environment & Sustainability > Environment > Oil and chemical spills (1.00)
- Facilities Design, Construction and Operation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract In oil industry economic context, the clean-up of wells through surface production facilities is an option in order to minimize environmental impact, economize rig days and commercialize produced clean-up oil. Clean-up operations through offshore topside production facilities started to be performed some years ago. However, many risks must be considered, especially production chemistry risks linked to compatibility between drilling/completion and production fluids. The goal is to ensure process stability and final quality of oil and produced water which, in many cases, must comply with rigorous specifications for coastal discharge or reinjection into the reservoir. This study shows the methodology developed to evaluate separation and deposits risks. As a general observation, experiments performed show a degradation of the separation process when drilling/completion fluids (completion brines and CaCO3 particles from drilling muds) are added to the emulsion. The most probable hypothesis is that some solid particles will adsorb at the oil-water interface and affect the stability of emulsions. Nevertheless, additives that change the wettability of solids seem to enhance separation, ensuring a separation efficiency equivalent to the system without particles. In the case of oils that contain very high molecular weight naphthenic acids (TPA), the use of brines with calcium chloride increases the risk of naphthenic salt deposits at topside facilities. The degradation of the water quality was also observed and the optimization of a reverse demulsifier is then required. The final clean-up strategy should also be adapted to topside design and possibilities to handle drilling fluids. How to separate and recover debris could be a problem for brown fields. For new projects, some additional provisions may be included in the design for well clean-up. In any case, a multidisciplinary risk evaluation is always required to ensure the good progress of this type of operations.
- Europe (0.67)
- North America > United States > Texas (0.55)
Abstract The traditional method of managing hydrates in production systems has been complete avoidance. This methodology comes at a high cost of insulation to maintain fluid temperature beyond the hydrate formation temperature and/or chemicals to prevent hydrates from forming. This paper will present methods to assess hydrate formation/plugging tendencies and manage the system in a manner that allows for reduction in insulation requirements and/or chemical usage. ExxonMobil's Upstream Research Company (EMURC) has developed a unique hydrate slurry model based on experience gained in the laboratory and field applications. Cold restarts are different than allowing fluids to remain cold indefinitely (i.e. cold flow) in that the hydrates form for a period of time before the system eventually comes out of the hydrate formation region in "steady-state/normal" production. This presentation will show how the model is used to assess hydrate blockage potentials by integration with a transient multiphase flow simulator. This enables the model to predict amounts of hydrates that form and couple the formation with flow dynamics such as shear conditions, phase fractions, and dispersion characteristics which influence the probability of a hydrate blockage forming. The model has been applied successfully to several applications by assessing various cold restart strategies in which significant cost savings have been realized through the reduction of insulation requirement and/or chemical usage – in some instances it has allowed for the extension of field life.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)