Enayatpour, Saeid (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX, USA) | Thombare, Akshay (Metarock Laboratories, Houston, TX, USA) | Aldin, Munir (Metarock Laboratories, Houston, TX, USA) | van Oort, Eric (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX, USA)
Oil and gas wells produce hydrocarbons for a limited number of years, and at the end of their production life they need to be plugged and abandoned. This process has to be done in a safe and economic way. Creep deformation of shale rock in uncemented casing sections may simplify well abandonments considerably. Creep can close the annular gap between a shale formation and an uncemented section of a casing string, generating a barrier that prevents hydrocarbons from flowing to the surface on the annular side. Wells with such a "shale-as-a-barrier" generated by creep now only require abandonment plugs on the inside of the casing, without the need for installation of additional annular barriers. This may eliminate such operations as casing milling and casing pulling, thereby allowing e.g. offshore abandonments to be done rigless, at significantly reduced cost.
This paper presents the first results of an experimental investigation and numerical modeling study into the nature of the "shale-as-a-barrier" phenomenon. Specifically, we focus on laboratory and field scale numerical simulation of creep behavior of North Sea Lark shale rock for oil and gas well plug and abandonment purposes. In our Finite Element simulations of the shale creep phenomenon, we have used the time-hardening creep model, which assumes a non-linear relationship between creep strain and stress, temperature and time. The model parameters were obtained from a curve fit of laboratory experimental results conducted for a creeping shale. Then, using the experimentally-derived parameters, numerical simulation was performed for a laboratory scale model and result was validated against laboratory results. Once this validation had taken place, the model size was extended to the field scale for prediction of annular closure time and barrier formation. Simulations show a strong correlation between rock stiffness and annular gap closure time, as expected; hence, the success of any "shale-as-a-barrier" project is a distinct function of shale rock stiffness. Lowering near-wellbore stiffness artificially may accelerate annular barrier creation of slowly creeping shale formations.
Shahri, Mojtaba (Apache Corp.) | James, Moisan (Apache Corp.) | Vasicek, Alan (Apache Corp.) | De Napoli, Roy (Apache Corp.) | White, Matthew (Apache Corp.) | Behounek, Michael (Apache Corp.) | D'Angelo, John (University of Texas at Austin) | Ashok, Pradeep (University of Texas at Austin) | van Oort, Eric (University of Texas at Austin)
Given the intensity of drilling operations in the North American unconventional reservoirs and the quality and amount of data gathered during a drilling operation, leveraging those data along with advanced modeling techniques for optimization purposes is becoming more feasible. In this study, historical data and advanced physical modeling are utilized to better understand and optimize the bottom-hole assembly (BHA) performance in drilling operations. A comprehensive data set is gathered for more than 300 BHA runs in the span of three years. This extensive data set enables thorough examination of the variation in the operational parameters and its effect on the drilling performance.
Different indices are used to determine and evaluate drilling performance, such as rate of penetration (ROP). Excessive tortuosity in a well can have many detrimental effects while drilling such as excessive and erratic torque and drag, poor hole cleaning (cuttings removal), low ROP, along with problematic casing and/or liner runs and associated cementing procedures. In this paper, a tortuosity index (TI) is used to quantify the drilled well quality and correlate it to ultimate drilling performance. In the next step, patterns are extracted and used along with physical modeling for optimizing drilling performance before the well is drilled.
The corresponding tortuosity index can be used as a proxy for the well path smoothness and may be used for quantifying parameters affecting drilling performance. According to historical drilling performance data, there appears to be a strong relationship between wellbore tortuosity and ROP. If drilling operating parameters (e.g., BHA configuration, directional company's performance, target formations, bit specification, mud types, etc.) can be related to the TI based on historical data, such parameters can be modified for optimizing the performance before the well is drilled.
By investigating the historical data, different trends have been extracted. In addition, different models can be built to predict drilling performance (e.g., TI) prior to drilling and according to new well design specifications. Based on data from more than 300 BHA runs and using advanced physical modeling, the most strongly correlated parameters to drilling performance have been determined and shown using different case studies. Such a historical database along with modeling techniques are used to predict well quality and drilling performance during the design phase. Using this method, well design specifications can then be optimized to enhance drilling performance and reduce the cost.
Accurate and frequent mud checking is critical to optimum well construction. Proper assessment and management of drilling fluid properties such as density and rheology maintain the primary well control barrier and optimize fluid hydraulics and hole cleaning ability. However, a full mud check while drilling is typically done only once or twice a day. Moreover, the measurements are performed using antiquated equipment, with data quality and reliability that are highly dependent on the practicing mud engineer. Automated, continuous and practical drilling fluid monitoring is therefore needed.
In this paper, we introduce an automated mud skid unit (MSU) which performs continuous drilling fluid sampling and measurements at variable temperatures. The unit is able to provide the non-Newtonian rheological constants characterizing a Yield-Power Law (YPL) fluid as well as the real-time friction factor and critical Reynolds number using a pipe-viscometer measurement approach. Other important fluid properties such as pressurized-density, oil/water ratio and temperature are provided using high-quality in-line sensors. The unit is controlled by a programmable logic controller (PLC) coupled with a Linux operating system for data analysis. The system is able to send real-time data to WITSML data servers and provide detailed mud reports to engineers working either on-site or remotely.
The MSU was deployed in the Permian basin by an independent operator for automated mud monitoring during unconventional shale drilling operations. Rheology, density and phase content measurements were compared with conventional mud reports provided by the on-site mud engineer. Excellent accuracy was observed in mud rheology tests. The pressurized mud-density measurements provided by the MSU proved to be more accurate than non-pressurized mud balance measurements which were affected by mud aeration. Moreover, the MSU provided mud check data 25 times more frequent than those generated by the mud engineer at temperatures of 50°C and 65.5°C. Drilling fluid related issues such as chemical over-treatment as well as sudden changes in mud density, rheology and oil/water ratio were reported immediately to the drilling crew. This paper provides details about the measurement technology as well as the results from the field deployment of the MSU.
Rostagno, Ian (The University of Texas at Austin) | Yi, Michael (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Potash, Ben (Pioneer Natural Resources) | Mullin, Chris (Pioneer Natural Resources)
Pipe rocking is a process used during slide drilling to reduce friction between the drillstring and the wellbore. Pipe rocking is widely practiced in unconventional drilling operations, either conducted manually or through an automated system. Often times, the rocking regime adopted in the field is based only on experience and may not be at optimum, leading to higher friction with poor force transfer to the bit and reduced rate of penetration. In addition, non-optimum pipe rocking can lead to accidental connection back-offs and poor toolface control.
This paper introduces the first rocking simulator based on real time and contextual data to provide the driller with a robust recommendation of the optimum rocking regime, i.e. guidance on the optimum number of forward and reverse wraps in the drillstring and the time period in which to generate these wraps.
A model was developed to optimize the pipe rocking regime, determined by the specifics of rotating the drillstring at a certain RPM for a certain number of turns in forward and backwards directions. The objective was to keep the directional toolface constant while optimally reducing sliding friction between the drillstring and the wellbore. A torque and drag model was used to obtain the frictional forces between the drillstring and the wellbore. Drillstring dynamics was then simulated using a torsional damped wave equation applying finite difference approximations. Finally, the angular deformation as a function of time and measured depth for each drillstring element was calculated.
Static friction is an important performance limiter when slide drilling with a downhole motor. Pipe rocking can be used as a low-cost technique to break the static friction in a section of the well and thereby reduce its negative effect. Pipe rocking simulation was used to find the rocking regime that maximizes the section of the string under conditions of dynamic friction, without losing toolface control. The torsional damped wave equation was used as a drillstring dynamics model because it successfully accounts for the surface rotational energy that is dissipated as elastic energy stored in the drill pipe and friction against the wellbore. Simulations resulted in recommendations to the directional driller on the optimum pipe rocking regime to adopt. The methodology was applied on a historical data set consisting of more than 100 US land wells. It was observed that improper pipe rocking could lead to back-off events, poor toolface control and reduced force transfer to the bit. By minimizing friction, longer horizontal sections and reductions in tortuosity can be achieved. An advisory software program was developed to guide directional drillers on favorable pipe rocking regimes based on contextual and real time data.
Wu, Qian (The University of Texas at Austin) | Nair, Sriramya (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Guzik, Artur (Neubrex Co., Ltd) | Kishida, Kinzo (Neubrex Co., Ltd)
A good cement-casing bond is essential for effective zonal isolation in both active and abandoned wells. A new method was developed to monitor the cement-casing bond in real-time and in-situ using a fiber optic distributed temperature and strain sensing (DTSS) system. To demonstrate the concept, the DTSS system was used in a laboratory-scale well model, which has a fiber optic cable installed helically on the outside surface of a steel pipe that served as a model for a casing string. A cement annulus was created by placing the steel pipe with the optical fiber into a larger PVC pipe. The DTSS system successfully captured strain changes at the cement-casing bond due to an axial load applied on the casing. The helical wrapping installation enabled circumferential measurements of temperature and strain changes in the entire cement annulus. The results were used to evaluate the risk of cement debonding by estimating the shear stress in the fiber and by comparing it to the shear strength of the cement bond. In addition, the effect of embedding a fiber optic cable on the hydraulic integrity of cement annulus was also evaluated using a gas permeability test. The permeability of cement samples with embedded fibers was found to be elevated compared to plain cement samples without fibers, but the permeability values were well within accepted industry limits. Compared to existing cement bond logging tools, the proposed fiber optic sensing system can provide continuous, real-time and in-situ monitoring of the cement bond and zonal isolation in either active or abandoned wells, without the need for wellbore entry. The system can serve as an early warning system to identify, and possibly prevent, the loss of a cement barrier, by providing detailed information (i.e. location, type, and severity of an event(s)) that will facilitate any remedial operations, if necessary.
Gu, Qifan (The University of Texas at Austin) | Fallah, AmirHossein (The University of Texas at Austin) | Ambrus, Adrian (The University of Texas at Austin, now with Norwegian Research Centre) | Chen, Dongmei (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin)
For robust and efficient automated Managed Pressure Drilling (MPD) operation, the choke controller requires a hydraulics model that is highly accurate and fast. The integration of a thermal model would be a great improvement for the hydraulics model's accuracy but has not been given sufficient discussion before.
In this paper, aquasi-steady thermal model is added to an automated MPD control approach that uses a reduced Drift-Flux Model (RDFM) for multiphase flow simulation. This provides the dynamic temperature profile in the well without increasing the computational expense. The energy equation is solved using the finite-difference method (FDM) in an explicit scheme, with all the temperature-dependent parameters updated in accordance with the calculated temperature profile in each loop. The RDFM is also reformulated to account for the heat transfer between the gas and the surroundings. This modified model is incorporated with an automated observer routine to estimate control parameters, e.g. volume of gas expansion (dependent on temperature), which are used by the controller for choke opening manipulation.
The simulation result of the proposed modeling approach for the scenario with a dynamic temperature profile are compared with that obtained with a validated full-order Drift-Flux Model (DFM) with an energy equation for validation. The dynamic temperature profile shows significant deviation from the steady-state temperature profile predicted in the absence of the thermal model. The proposed model is also compared with the RDFM without adding energy equation to show the improvements with the addition of thermal model. Moreover, accurate temperature modeling during multiphase flow situations is essential to achieving high-fidelity influx control and handling. The updated controller incorporating the new thermal model was tested, and the performance of the choke controller turned out to be faster and more precise than the previous controller which was based on a RDFM without energy equation. The computational cost of this modified model was also tested in a full-scale wellbore geometry with two-phase flow. The calculation time is of the order of ~70ms for 1s sensor data sampling on a normal PC, which is more than sufficient for automated real time control.
Olvera, Raul (Department of Civil, Architectural and Environmental Engineering, The University of Texas at Austin) | Panchmatia, Parth (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Juenger, Maria (Department of Civil, Architectural and Environmental Engineering, The University of Texas at Austin) | Aldin, Munir (Metarock Laboratories) | van Oort, Eric (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
Volume changes due to shrinkage are inherent to the hydration process of ordinary portland cement (OPC) and alkali-activated cementitious materials. Under elevated temperature and pressure conditions, as is the case in oil and gas wells, the internal stresses created by shrinkage can result in loss of zonal isolation and the need for expensive repairs. This paper compares the early age shrinkage behavior of Class H OPC, alkali-activated Class F fly ash (referred to as geopolymer in this study), and geopolymer-hybrid (geopolymers incorporating drilling mud) slurries with up to 20% (by volume) synthetic based mud (SBM) contamination cured at 23 C and 50 C. In addition, the use of zinc and aluminum-based expansive agents to mitigate shrinkage was explored. Results from various test methods characterizing shrinkage behavior show that (a) shrinkage increases with temperature for all cases, (b) geopolymers shrink less than OPC slurries at low temperature, (c) geopolymer shrinkage exceeds that of OPC slurries at higher temperatures, (d) the addition of SBM increases the shrinkage of both OPC and geopolymer slurries, and (e) the use of suitable expansive agents has the potential to neutralize shrinkage of both OPC and geopolymer slurries. The work also shows that the current set of ASTM and API shrinkage tests need to be augmented with a test that can be conducted at elevated temperature and pressure, particularly when testing expansive agents that generate gases. A proposal for a more relevant test is included.
Gul, Sercan (The University of Texas at Austin) | Johnson, Mitchell David (The University of Texas at Austin) | Karimi Vajargah, Ali (The University of Texas at Austin) | Ma, Zheren (The University of Texas at Austin) | Hoxha, Besmir Buranaj (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin)
Managing drilling margins in challenging wells requires precise prediction of frictional pressure losses and equivalent circulating density (ECD). Current hydraulic models in the industry fail to accurately predict the frictional pressure losses of certain mud formulations in turbulent flow due to the complex behavior of long-chain polymer additives. These additives facilitate friction reduction in certain flow regimes. This reduction depends on several parameters, such as molecular weight and chemical composition of the polymers, making it difficult to quantify using existing models. In this paper, a data-driven approach is proposed to precisely predict frictional pressure losses for polymer-based fluids.
A flow-loop was constructed to measure frictional pressure-losses of several polymer-based non-Newtonian fluids under laminar, transitional, and turbulent flow regimes. Pressure loss data was obtained for fluids with different polymer concentrations at various temperatures using differential pressure measurement. A database of the experimental data was compiled and used to build a predictive model for frictional pressure prediction using advanced machine learning techniques. The proposed approach has general validity and can be extended to any type of well construction fluid (used in drilling, completion, stimulation, or workover).
Results for frictional pressure loss predictions from the proposed data-driven approach were compared with both the experimental data and widely used industry models. An excellent agreement was observed between the proposed approach and the experimental results, demonstrating the applicability of this approach for hydraulic modeling of polymer-based fluids. The improvements are particularly noticeable at higher polymer concentrations in the turbulent flow regime, where the average percentage discrepancy between the existing models and the experimental data can be as high as 45%.
The proposed approach in this study is particularly valuable for wells with a narrow drilling margin and concerns about the ability to manage ECDs (such as slim hole wells, deepwater wells or extended reach wells). It can assist with better planning and avoiding non-productive time and drilling problems such as lost circulation, stuck pipe, wellbore instability, and well control events. Its adaptability to a wide range of fluids using an expanded database makes it particularly attractive as a practical solution to this challenging problem.
D'Angelo, John (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Shahri, Mojtaba (Apache Corp.) | Thetford, Taylor (Apache Corp.) | Nelson, Brian (Apache Corp.) | Behounek, Michael (Apache Corp.) | White, Matthew (Apache Corp.)
Wellbore tortuosity is an important metric of wellbore quality; however, it is not always an appropriate reflection of directional drilling performance. Drilling planned tortuous features will increase wellbore tortuosity, but this in itself says nothing about directional drilling performance. Not only is there a need for a metric of wellbore tortuosity, it isalso necessary to have a metric of "unplanned" wellbore tortuosity. The former provides information about wellbore quality, whereas the latteris reflective of directional drilling performance.
The directional drilling literature contains metrics for both wellbore and unplanned tortuosity; however, they are largely unique and difficult to relate to one another. It is desirable for the planned and unplanned tortuosity metrics to be relatable. This would allow operators to not only quantify overall wellbore tortuosity in real time, but also to understand how much of that tortuosity is unplanned and possibly avoidable. This, then, opens up avenues for directional drilling performance improvement.
In this paper, a new metric, the "Unplanned" Tortuosity Index is developed on the basis of an existing metric of wellbore tortuosity. This is done by systematically removing the effects of intended tortuous features from the wellbore tortuosity analysis, retaining only those tortuous features in the wellbore trajectory that are unplanned. The unplanned tortuosity index is then tested on two distinct sets of survey data from actual wells drilled. The results are compared between the sets and with the wellbore tortuosity metric from which the new index was derived. It is shown that thenewly developed unplanned tortuosity index canhelp operators and directional drilling companies discern their directional drilling performance, especially forwell paths with multiple, planned tortuous features.
Fallah, AmirHossein (The University of Texas at Austin) | Gu, Qifan (The University of Texas at Austin) | Ma, Zheren (The University of Texas at Austin, now with Quantum Reservoir Impact) | Karimi Vajargah, Ali (The University of Texas at Austin, now with Quantum Reservoir Impact) | Chen, Dongmei (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | May, Roland (Baker Hughes, a GE company)
There is a growing need for comprehensive multi-phase hydraulic models that can accurately model more complex well control situations associated with the use of Managed Pressure Drilling (MPD) techniques, complex well geometries, High-Pressure High-Temperature (HPHT) conditions, riser gas unloading, etc.
A new thermal model integrated with previously developed multi-phase hydraulics software is presented here to address this need. This de-coupled thermal model is added to a sophisticated multi-phase flow code to estimate the mud temperature in the drillstring and the annulus and in the formation adjacent to the well during complex well control situations. The model uses an explicit finite volume approach and solves the mixture energy equation for the wellbore fluids, assuming that all the phases are at thermal equilibrium. Heat transfer between the drillstring and the wellbore fluid, and between wellbore and formation is calculated using a thermal resistance network. Axial heat conduction in the mud and heat generation (e.g. at the bit) are accounted for. The steady-state results of the proposed thermal model are compared to the steady-state Hasan and Kabir model and commercial software. In addition, the transient, time-dependent temperature behavior during mud circulation is compared against the results of the commercial software. Results show a very good match for both steady-state and transient cases.
Kick scenarios are simulated to show the importance of accurate temperature estimation of the drillstring and annulus fluids in HPHT conditions. Using advanced numerical schemes, a comprehensive model for heat transfer and energy storage in combination with a user-friendly Graphical User Interface (GUI) makes this model a robust tool for estimating the transient temperature profile of the mud and the formation. The model allows for evaluation of crucial parameters during well control, such as the wellbore pressure and temperature profiles, increased outflow and pit gain during kicks, gas thermodynamic behavior including solubility and unloading at low pressure conditions, gas rising velocity, and even temperature-dependent formation strength. These added features provided by the model come without loss of previous modeling capabilities, such as accounting for area discontinuity in the well and drillstring, gas dissolution in mud, non-Newtonian fluid rheology, MPD techniques, and arbitrary 3-D well trajectories.
Details of the new model and the simulation approach are shared, and various applications of the new thermal modeling capability are illustrated.