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Producer-flowline temperatures (FLTs) can be measured automatically with a thermistor on an emergency-shutdown system (ESD), or manually on a specified spot on flowline with a handheld unit. Measured FLTs can usually be mapped to represent the formationtemperature distribution for steamflood reservoir management purposes (Hong 1994; Nath et al. 2007). In addition to FLT, wellhead temperature (WHT) is another surface temperature. Predicting the long-term WHT trend in steamflood operation is necessary for designing surface facilities for both oil dehydration/separation and produced-water recycling. This predicted temperature will also be applicable for production-performance monitoring.
To predict the wellhead temperature, Hasan et al. (2009) derived a steady-state analytical solution for calculating WHT from bottomhole temperature (BHT) under flowing conditions of a multisection slant wellbore for the isothermal primary-depletion process, with both WHT and BHT being time independent for a given gross rate (Igec et al. 2010). This steady-state analytical solution has been extended to calculate steamflood producer WHT from BHT (both are time dependent) by consecutively approximating the WHT and monthly average of FLT measurements to a steady-state solution. The monthly averaged FLTs are seasonally variable and higher in the summer months of July through September and lower in the winter months of December through February. Monthly averaged FLT measurements depend on an annual ambient-temperature cycle within the depth needed for reaching an undisturbed ground temperature (typically 30 to 50 ft) (Gwadera et al. 2017). WHT, if measured, should be comparable with FLT for their close typical distance of 5 to 10 ft. WHT prediction, however, is only process dependent and not seasonally variable because of the inability to describe seasonally undisturbed depth in the geothermal gradient. Therefore, WHT prediction can be validated with average summer-month FLT measurements when heat loss becomes minimal. BHTs in this analytical approach are predicted by the Lauwerier (1955) analytical model and improved by calibration with the available reservoir-simulation model or several years of FLT measurements for steamflood response time.
The objective of this study is to develop an integrated production-monitoring approach using only the surface information, including WHT and FLT, oil/water-production rate, and injection-pressure/rate data, which can be applied to diagnose and optimize steamflood production performance. A field case study for the South Belridge Diatomite steamflood was investigated. WHT prediction is compared with FLT measurement for diagnosing and understanding the production performances, such as premature water or steam breakthrough, interference by the waterflood on the steamflood boundary producers, as well as the FLT variation related to the target rates for steam injection. This diagnostic analysis approach combined with the Buckley-Leverett theory-based displacement-efficiency analysis, and injection pressure and rate signal, will help to develop an improved understanding of the displacement detail and form a decision base to optimize the production performance.
Producer flow line temperatures (FLT) can be measured automatically with a thermistor on an emergency shut-down system (ESD), or manually on a specified spot on flow line with a hand-held unit. Measured FLTs can usually be mapped to represent the formation temperature distribution for steamflood reservoir management purposes (
To predict the wellhead temperature,
A field case study for the South Belridge diatomite steamflood was investigated. WHT prediction is compared with FLT measurement for diagnosing and understanding the production performances such as water or steam premature breakthrough, interference by the waterflood on the steamflood boundary producers, as well as the FLT variation related to steam injection target rates. This diagnostic analysis approach combined with the Buckley-Leverett theory based displacement efficiency analysis, and injection pressure and rate signal, will help to develop an improved understanding of the displacement detail and form a decision base to optimize the production performance.
Some of the first high-pressure/high-temperature (HP/HT) development wells from Elgin and Franklin have been exposed to sustained casing pressures in their "A" annulus, threatening the integrity of the wells. The sustained pressure in the annulus was attributed to ingress through the production casing of fluids from the overburden chalk formations of the Late Cretaceous. The mechanism triggering the ingress into the "A" annulus was uncertain until access to the production casing was achieved. A recent campaign to abandon development wells of Elgin and Franklin that had sustained "A"-annulus pressure brings new evidence on the mechanism causing the ingress. Temperature surveys have been acquired in the production tubing to identify the fluid-entry points in the production casing. Multifinger calipers have been run in the production casing, revealing several shear-deformation features. These deformations are localized along various interfaces, and are attributed to the stress reorganization associated with the strong reservoir depletion. A detailed analysis of the surveys shows that fluid ingress is occurring at distorted casing connections, if located close to weak interfaces along which shear slip occurs. The shear deformation is suspected to cause a loss of the sealing capacity of the connection, leading to gas ingress into the "A" annulus. This conclusion emphasizes the need to consider any potential for localized shear deformations in designing casing for HP/HT wells.
Thermohydromechanical effects can have significant impacts on the operations of heavy oil and geothermal fields. This motivates the use of accurate reservoir simulators in field development planning. Previously, simulation using continuous Galerkin methods was examined. However, these methods can experience difficulty in convection-dominated flow problems. Consequently, the discontinuous Galerkin method was considered as an alternative. The discontinuous Galerkin method's literature suggested the need to state a generalized, single-phase thermohydromechanical formulation to clarify previous work. This paper states this generalized formulation and performs a poromechanical benchmark of uniaxial compaction in FEniCS using the discontinuous Galerkin method. Additional work on extension to multiphase flow and the incorporation of thermal effects is needed.
Compaction-induced casing damage, particularly adjacent to reservoir boundaries, has been observed in many fields. As part of mitigation planning for potential casing collapse due to reservoir compaction, expensive numerical models are often employed to quantitatively assess casing strain under simulated reservoir conditions. In order to simplify casing deformation analysis and reduce analysis time, the current study was initiated to quantify the effects of depletion magnitude, rock compressibility, borehole orientation, casing diameter-to-thickness ratio (D/t ratio) and grade on compaction-induced casing deformation using finite element modelling (FEM). The model results allowed an empirical equation to be derived to predict casing strain that is sufficiently accurate for engineering applications.
The objective of the study was achieved by building a series of 3D FEM models to systematically simulate the deformation of casings cemented perfectly within a horizontal reservoir that underwent up to 8.3% compaction due to depletion. To capture the pattern of casing strain variation adjacent to the reservoir boundaries, the simulations were run over a range of borehole deviations (0°, 22.5°, 50°,67.5° and 90°). For each borehole deviation, casing D/t ratios of 8.14, 19.17 and 32.67 and grades of 40 ksi, 90 ksi and 135 ksi were defined to evaluate their impact on casing strain variations.
The FEM models show that casing deformation adjacent to reservoir boundaries is accommodated by radial expansion and axial shortening in vertical wellbores, while the deformation is characterized by bending in deviated wellbores. The maximum strain adjacent to reservoir boundaries varies systematically, but nonlinearly with each variable evaluated. The maximum strain increases with reservoir compaction strain, i.e. increases with rock compressibility and depletion, but decreases with increasing hole deviation. Both casing D/t ratio and grade affect casing strain, but their effects are secondary. In general, the maximum strain is greater for casings with smaller D/t ratios and higher grades at any given borehole deviation and compaction strain. The variation of the maximum casing strain with compaction strain can be described by a power law. Both its constant and exponent are functions of borehole deviation, casing D/t ratio and grade.
Because of the complexity of borehole-reservoir geometry and casing plastic behavior, there is no analytical solution available to estimate compaction-induced casing strain adjacent to reservoir boundaries. Numerical models may be used to predict the casing strain, but the numerical analysis is time consuming and requires specialist knowledge. The equation proposed from this study is sufficiently accurate compared to numerical models in terms of casing strain prediction, but provides a much simpler and quicker analysis. In addition, the study provides insight on the variation of casing strain with the major controlling factors, leading to a more complete understanding of compaction-induced casing deformation.
Thermal recovery operations, including those in heavy oil fields and geothermal reservoirs, can benefit from increased understanding of thermo-hydro-mechanical (THM) phenomena. Maximizing thermallyenhanced energy recovery and assessment of thermally-induced seismicity and subsidence risk requires the next generation of coupled THM simulators that are easier to develop and use. We present a computational framework based on automated linearization and solution of multiphysics equations using FEniCS, an open source finite element solver. We validate the simulator on benchmark problems and discuss its application to thermal enhanced oil recovery methods. We conclude that using the FEniCSbased framework can reduce code development and maintenance efforts in existing thermal recovery operations and accelerate the discovery of future improved thermal recovery methods.
InSAR (Interferometric Synthetic Aperture Radar) is a technology used to measure changes in surface elevation between successive passes of orbiting satellites. These changes can be used to understand imbalances in the subsurface between fluid withdrawal and injection, as well as near-surface ruptures caused by failure of well integrity.
Satellites have recorded SAR data since the 1990s, and the data have become increasingly higher resolution and more frequently acquired. Combined with faster algorithms and processing chains for interferometry, this has enabled detection of smaller and faster changes at the surface. This in turn has caused a step-change in the usefulness of the data and the interpretations. The result is the ability to depend on the data to monitor the effects of production and injection processes almost continuously.
We review several cases to demonstrate the value of rapid revisit, high resolution InSAR. The first is the giant Belridge field in the San Joaquin valley of California, historically the poster child for this application. The diatomite reservoir rock has 60% porosity and is fluid supported. When equilibrium between injection to production is not maintained, the volume changes in the reservoir cause the ground surface to move up or down by amounts detectable with InSAR enabling a feedback loop for injection optimization. The field also has many wells with compromised wellbore integrity that can provide a pathway for reservoir fluids to move upwards towards the ground surface. When water, oil, or steam move out of the reservoir and into the overburden, a potential precursor can be detected provided InSAR is configured carefully. In the second case, InSAR also provides visualizations of ground level changes over a gas field: at the giant Groningen gas field in the Netherlands, long term InSAR time series measurements of elevation changes are used to constrain models about compaction and reactivation of buried faults. Parts of the field that are used for seasonal gas storage and charging/discharging cycles can also be effectively monitored.
Measurement of surface deformation by high resolution, fast revisit, optimized InSAR provides an insight into the reservoir and the efficiency of its management. It also provides an early warning of potential problems that, if not corrected, may result in harm to the environment. These step changes in quantity and quality of available InSAR data mean that the remaining barrier to being used for actionable insights is in the widespread inverse modeling of the surface data to sub-surface mass flows.
Depletion of oil and gas reservoirs results in ground surface subsidence and wellbore damage. Accurate prediction of subsidence and wellbore damage can provide a strong support to reservoir management and community precaution on subsidence impact. For reservoirs with soft rock formations, depletion-induced reservoir compaction results in serious damage and permanent deformation of rock formation. Cap plasticity models are crucial to achieve a more reliable prediction on the compaction of reservoirs with soft rocks. In this study, we develop a fully coupled and fully implicit finite element framework along with cap plasticity models for modeling the compaction of reservoirs with soft formations undergoing finite deformation. Creep models are also formulated with cap plasticity models for predicting the long-term effect of reservoir compaction. A material integrator for stress return mapping for both plasticity and creep models is consistently formulated to achieve fast convergent rates. A reservoir compaction model with three horizontal production wells and a wellbore damage model are solved using the proposed computational framework as well as cap and creep models with parameters obtained from field tests. We have demonstrated: 1) a good performance of the proposed computational framework in modeling the compaction of soft rock reservoirs with complex payzone geometries; and 2) the predicted subsidence with cap plasticity models could be seven times greater than linear elastic or plasticity models without caps.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Turkish Petroleum) | Inceisci, Turgay (Turkish Petroleum) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Tran, Minh (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | AlKouh, Ahmad (College of Technological Studies) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
As an increasing number of thermal wells are drilled in arctic and subarctic regions, such as the north slope of Alaska and northern Canada, there is an urgent need for lightweight cement systems with thermally insulating properties. Significant temperature changes resulting from activities such as shut-in, steam injection, and production can lead to increased temperatures in the wellbore. As the wellbore temperature rises, there is an increased risk of melting permafrost, which can allow the formation to move and result in costly damage to the well. Lightweight and thermally insulating cement would contribute to the life of a well by maintaining low thermal conductivity while providing structural support for the casing strings. This study compares the thermal and mechanical properties of water-extended, foam, and microsphere cements with densities of 1.32, 1.50, and 1.68 specific gravity (SG) (11, 12.5, and 14 lbm/gal).
To simulate several different conditions in a well, thermal conductivity of the foam system was measured for dried, as-poured, and saturated conditions. While the amount of air or fluid in the foam samples influenced the measured thermal conductivity, both microsphere and foamed systems appeared to be comparable.
Initial findings from mechanical properties testing demonstrated foamed slurries have higher tensile and compressive strengths. Under confining pressure, the foam cement system had a larger failure envelope and would be able to withstand greater downhole pressure increases compared to the microsphere design at the same density.
When designing wells in areas with permafrost, including a cement system with low thermal conductivity would help minimize the risk of melting the permafrost and maximizing the longevity of the well. This paper reviews several possible lightweight solutions and presents the thermal and mechanical properties of various foam and microsphere cement designs.