East Gulf Coast Tertiary Basin
ABSTRACT The Port Isabel passive margin foldbelt covers 17,000 km of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5–7 km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.86)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.94)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (21 more...)
ABSTRACT The Port Isabel passive margin foldbelt covers 17,000 km of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5–7 km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.86)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.94)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (21 more...)
Stones Gulf of Mexico Single-Phase Subsea Pump Operation Under Gas Conditions to Enhance Production
Barrios, L. (Shell Exploration& Production, Houston, Texas, USA) | Merlino, A. (Shell Exploration& Production, Houston, Texas, USA) | Brutz, J. (Shell Exploration& Production, Houston, Texas, USA) | Whitaker, K. (Shell Exploration& Production, Houston, Texas, USA) | Overstreet, J. (Shell Exploration& Production, Houston, Texas, USA) | Arkhipova, K. (Shell Exploration& Production, Houston, Texas, USA) | Rojas, M. (Shell Exploration& Production, Houston, Texas, USA) | Dowdy, B. (EDG, Inc, Houston, Texas, USA) | Pisarev, G. (SLB Company, Houston, Texas, USA) | Solvoll, F. (SLB Company, Houston, Texas, USA)
Abstract In a Gulf of Mexico ultra-Deepwater field (with a water depth of 10,000 ft), high-boost single-phase centrifugal subsea pumps operation under gas conditions were used to optimize overall field production by lowering the pump suction pressure below the bubblepoint to safely operate the pumps under two-phase liquid and gas production. The subsea single-phase pump (SPP) system used in Stones Field comprises multistage centrifugal pumps for high-rate (30,000 B/D) and high-boost applications. In pump applications, multiphase flow can cause problems such as performance degradation, system inefficiency, and failures that must be considered to safely operate pumps under free gas flow. Stones pressure/volume/temperature (PVT) fluids have a range of uncertainties, leading to bubblepoints from 900–1,200 psia. Subsea Single-phase pump has been in operation in Stones since 2019, with a minimum suction pressure operating limit of 1,200 psi. The primary objective in further decreasing the suction pressure to operate below the bubblepoint was to increase the overall production through a process that integrated risk assessment, pump performance and flowline dynamic modeling, topside considerations, operating procedures, and a management of change process to approve opportunity and move to execution. Risk assessment and operator in-house pump expertise were key enablers to assess the feasibility of the opportunity and define the primary risks to the artificial lift system while operating below the bubblepoint. A risk/value tradeoff was performed to understand value over pump failure for the Stones overall production. Following implementation, a detailed surveillance strategy was put in place to mitigate the primary risks associated with the pump operating with allowed free gas. Up to today a total net gain of approximately 10% is being increase in the overall Stone production operating subsea pump below bubble point at 875 psia suction pressure. The primary technical contributions of this work are the detailed technical approach and the use of analysis and data with field operation to predict pump performance and safely operate the pumps in two-phase flow in the SPP.
- North America > United States > Texas (0.89)
- North America > United States > Gulf of Mexico > Central GOM (0.49)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- (2 more...)
Integrated wellsite biostratigraphy and chemostratigraphy: A multidisciplinary approach for drilling the Wilcox
Pearce, Tim J. (Chemostrat Ltd.) | Cornick, Paul (PetroStrat Ltd.) | Riley, David (Chemostrat Ltd.) | Campion, Neil (PetroStrat Ltd.) | Daneshvar, Ehsan (Future Geoscience Ltd.) | O’Neill, Paul (Future Geoscience Ltd.) | Hildred, Gemma (Chemostrat Inc.)
This study proposes an integrated multidisciplinary workflow for the correlation of wells within the Gulf of Mexico. Integrating wellsite biostratigraphy and chemostratigraphy. Wells previously analysed for biostratigraphy have been subjected to elemental analysis by Inductively Coupled Plasma - Optical Emission Spectrometer (ICP-OES) and Inductively Coupled Plasma - Mass Spectrometer (ICP-MS) analysis, as well as x-ray fluorescence (XRF) in a simulated wellsite situation. The newly implemented workflow in this study exhibits a robust correlation between biostratigraphy and chemostratigraphy, leading to a more confident identification of major intra Wilcox surfaces.
- North America > United States (0.36)
- North America > Mexico (0.26)
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Biostratigraphy (1.00)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Gulf of Mexico > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
The Port Isabel passive margin foldbelt covers 17,000 km2 of the northwestern, deepwater U.S. Gulf of Mexico (GOM). Seven oil exploration wells were drilled in the area from 1996 to 2007, yielding a single, uncommercial gas discovery. The 5-7 km thick Oligo-Miocene section prevented drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section was created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the west. We used 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpreted a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses, younger and shallower Wilcox source rock horizons, and interpreted Jurassic and Cretaceous source rock horizons. Our results show vitrinite reflectance as a proxy for the thermal stress levels reached by the source rocks combined with maps of hydrocarbon charge access. We conclude that all three source rock intervals reached varying degrees of maturity and expelled hydrocarbons in late Paleogene to mid-Neogene and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section buried the underlying source intervals and likely brought them into the gas/condensate window at present-day. Our mapping of the seismic grid revealed four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Thermal stress maps predict source rocks have matured. There arises a need to investigate the hydrocarbon migration model, including assessing charge access for each well. The timing of late trap formation and early hydrocarbon charge remains a risk factor.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- North America > United States > Gulf of Mexico > Western GOM (0.85)
- Phanerozoic > Cenozoic > Paleogene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.68)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.68)
- Geophysics > Seismic Surveying > Seismic Processing (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (22 more...)
Integrated Petrophysical Studies for Subsurface Carbon Sequestration
Bhattacharya, Shuvajit (Bureau of Economic Geology, The University of Texas at Austin) | Bakhshian, Sahar (Bureau of Economic Geology, The University of Texas at Austin) | Hovorka, Sue (Bureau of Economic Geology, The University of Texas at Austin) | Uroza, Carlos (Bureau of Economic Geology, The University of Texas at Austin) | Hosseini, Seyyed (Bureau of Economic Geology, The University of Texas at Austin) | Bump, Alex (Bureau of Economic Geology, The University of Texas at Austin) | Trevino, Ramon (Bureau of Economic Geology, The University of Texas at Austin) | Olariu, Iulia (Bureau of Economic Geology, The University of Texas at Austin) | Haagsma, Autumn (Battelle, currently Michigan Geological Repository for Research and Education)
ABSTRACT Petrophysics is a core component of subsurface characterization and monitoring design for carbon capture and storage (CCS). In the United States, Environmental Protection Agency (EPA) underground injection control (UIC) rules for carbon storage (class VI wells) include subsurface characterization, CO2 plume stabilization, Area of Review (AoR) modeling, and monitoring during pre-injection, injection, and post-injection, where petrophysicists can play important roles. We discuss some important petrophysics-related questions and their significance relevant to CO2 storage and plume migration using simplified reservoir simulation models and show examples from three petrophysical case studies in Miocene and Wilcox formations on the Gulf Coast, Texas and fractured Trenton-Black River group in Michigan. The simulations provide a first-principle understanding of CO2 plume migration and controlling factors that petrophysicists can analyze. INTRODUCTION Over the last two decades, several CCS demonstration projects have been completed around the world (including US, Canada, Norway, Australia, and Japan), some of which were successful in showing the feasibility of CO2 storage in the saline aquifer and depleted reservoirs (Furre et al., 2017; Gupta et al., 2020; Hovorka et al., 2013). Recently, Global CCS Institute (2022) provided a comprehensive status update on CCS facilities in different operational and development stages around the world. These studies have indicated that we need a large injection reservoir (or stacked reservoirs) with sufficient pore space, reservoir connectivity, and injectivity that can accept commercial rate and volume of CO2 injection over time as well as a confining system overlying the entire AoR to prevent vertical migration of CO2 [AoR represents the region that may be affected by the injection of CO2; please see Directive 2009/31/EC, 2009; US EPA, 2011; ISO/TC265, 2017 for details on regulatory definitions]. These projects also facilitated the transfer of certain oil and gas knowledge, technologies, and workforce to CCS. However, most of these demonstration projects to date have largely been first-of-a-kind and isolated in nature (Bump and Hovorka, 2023). Some of these projects had a small areal extent and collected a significant volume of petrophysical logs and core data from a very limited number of wells for high-resolution site-specific modeling, storage capacity estimates, and monitoring. This approach is not always beneficial to offer a broad systems-level understanding of the petrophysical requirements and solutions for carbon storage-related subsurface characterization and monitoring. Site-specific CCS approach has been myopic in some sense that it has not always yielded deep geologic insights into the basin-wide understanding of reservoir connectivity, CO2 injectivity, and sealing capacity.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
The success of a major deepwater capital project is significantly influenced by how well capital and schedule commitments made at the time of Final Investment Decision (FID) are met. Front End Loading (FEL) activities are the Operators’ work processes leading up to FID. FEL includes reservoir characterization and appraisal, definition of the well construction program and the facilities (production platform, subsea, umbilicals, risers and flowlines (SURF), export systems) that process and export reservoir fluids. Most deepwater developments can be categorized as major capital or megaprojects, with capital costs ranging from $3 billion to $10 billion. The offshore industry's track record for delivering megaprojects within sanctioned budget and schedule is not stellar. Project economics are seriously eroded if budgeted cost and schedule slip by more than 10%. There are many reasons for slippage, but a root cause is the inadequate allocation of contingency and availability of accurate, current benchmarking data. Operators require independent cost and schedule benchmarking of risked capital costs and Sanction to First Production (STFP) schedules, established at the end of FEL, to validate contingencies before green lighting a project. Schedule benchmarking compares risked STFP schedule at FID to actual STFP of an analogous project in production. The fabrication, integration, transport, installation, hook up and commissioning of the Floating Production Unit (FPU) is typically on the critical path to first production. Since the FPU topside operating weight is a key schedule driver, schedule benchmarking is comparing the planned STFP of the project awaiting sanctioned to the actual STFP of a producing analogoue FPU project with a topside of similar operating weight and complexity.
- Asia (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.93)
- Europe (0.70)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- (34 more...)
Abstract “The present is the key to the past” is a foundational geologic concept that helps us contextualize buried subsurface features in current geologic analogs. As seismic interpreters, the generation of the geologic model should be unbiased, yet as humans our unconscious biases are expected, and we sometimes overlook anomalous reflection patterns in our seismic data that do not fit the model. As a result, we often disservice ourselves when we overlook these characteristics, potentially ignoring additional geologic context. These anomalous geoforms or funny-looking things (FLTs) may provide further geologic context and aid us in solving the geologic model if included. Crevasse splay on a continental slope marine environment is described and analyzed using attributes, seismic inversion, and voxel-based classification. We discuss possible causes that may have triggered the break of the levee on the Exmouth Basin during the Early Eocene and why a crevasse splay on a steep slope is an FLT. A possible explanation is that the presence of preexisting faults beneath said feature is the likely culprit for a levee break that created the crevasses splay. Thus, in contrast with the Led Zeppelin song about why the levee breaks, it is equally important to understand the preexisting faults when analyzing sediment supply. In addition, this highlights the importance of integral stratigraphic sequence interpretation — from deep to shallow — to understand geology in a full context. Geologic feature: Crevasse splays and distributary channels Seismic appearance: Mounded high-amplitude reflection with hummocky low-amplitude internal reflection on vertical section, subparallel overlapping sinuous features on seismic attribute horizon slice Alternative interpretation: Mass-transport deposit, avulsion node; channel overbank Formation: The Wilcox Formation Age: Early Eocene-Late Paleocene Location: Offshore Western Australia Seismic data: Stybarrow 2008 M4D MSS obtained by the Geoscience Department of Australia Analysis tools: Coherence, multispectral coherency, principal curvature (K1 and K2), acoustic seismic inversion, flatness and curvedness, CNN automatic fault interpretation, and spectral decomposition
- Oceania > Australia > Western Australia (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.24)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Ypresian (0.45)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Lutetian (0.45)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous > Campanian (0.40)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.70)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Oceania Government > Australia Government (0.48)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-32-L > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > Carnarvon Basin > Exmouth Basin (0.99)
- (4 more...)
Abstract This paper presents a new concept of Pseudo-Aquifer Index and a major departure from classical methods to estimate transient water influx using Kumar-Ramey equation employing reservoir average pressure obtained from transient tests for a central well in a constant pressure reservoir. The new method overcomes the two limitations of the conventional methods of van Everdingen-Hurst (1949), Carter-Tracy (1960), Fetkovich (1971), and similar other studies. These methods require apriori knowledge of (1) pressure history at the reservoir-aquifer boundary (oil-water contact or OWC) with time, and (2) aquifer characterization in terms of rock and fluid properties, depth, and geometric configuration. Such data for aquifer and OWC pressure history carry a high degree of uncertainty at the beginning of a newly discovered complex offshore or onshore reservoir development. Kumar-Ramey (1974) presented dimensionless water-influx (WeD) as a function of dimensionless average pressure and producing time which yields cumulative water-influx volumes as a fraction of cumulative reservoir withdrawal. Kumar (1977) also provided the dimensionless pressure at the reservoir aquifer boundary with time. Plots of dimensionless average pressure, dimensionless boundary pressures at the OWC, and cumulative water influx function (WeD) are presented as a function of producing times for the three cases of pseudo-aquifer-index of 0.25, 0.50, and 1.0. Some of this data is obtained from Kumar (1977) and is transformed into polynomial equations. Two examples show the applications, and compare transient water-influx results with those obtained from van Everdingen-Hurst method. A log-log type curve of dimensionless average pressure and time is included for determination of reservoir properties when average pressure is known A considerable advantage of the new method is its simplicity, generality, ease in use, and implementation in reservoir engineering software and simulation when compared to conventional methods. This study is also the first to provide a systemic characterization of transient boundary (OWC) pressures in closed and partial water drive reservoirs.
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Gulf of Mexico > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
ABSTRACT: This paper strives to model and validate annulus fluid and casing temperature profiles during wellbore warmback after fluid circulations. Modeling is based on published analytical methods. A research test well has been drilled to a predefined temperature target which can help validate the modeling results. Multiple live-streaming and memory tools are run to provide downhole temperature measurements during drilling, circulation, shut-in, cementing and post-drilling circulation/shut-in (warmback) operations. A permanent distributed fiber optic (FO) system, installed outside of the production casing, provides continuous downhole temperature measurements. One open-hole (OH) warmback and two cased-hole (CH) warmbacks were analyzed. The difference between modeled and measured temperature is within 3°F for the two cased-hole cases. With limited bottom hole temperature (BHT) measurements, the difference of the BHT is within 6°F for the open hole case. Dimensionless temperature studies show that after the dimensionless shut-in time reaches 9 for OH case and 20 for CH case (for the base-case formation thermal diffusivity) the difference between BHT and SFT (static formation temperature) reaches 10% of the difference between the wellbore temperature at the end of the circulation and the undisturbed SFT. For a given wellbore configurations and with 0.03 ft/h (7.74e-7 m/s) formation thermal diffusivity, this critical time corresponds to about 49 and 40 hours for the open hole and close hole cases, respectively. The models and results described in this paper can be applied to temperature log timing determination, geothermal well design, underground energy storage and geothermal recovery processes. 1. INTRODUCTION A good estimate of annulus fluid temperature in a wellbore plays an important role in drilling operation as well as in determining and possibly extending the operating range of various downhole tools. In geothermal drilling, for instance, most downhole tools involving electronic components become ineffective beyond about 175°C. A properly designed mud chiller or insulated drill pipes can extend the temperature limits. This requires a good thermal management approach. In this paper, we demonstrate the validity of some of the existing analytical models for wellbore thermal profile estimation by comparing them with measured data.
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Gulf of Mexico > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)