bluuebunny/crossref_metadata_2025 huggingface dataset:
Well Integrity Management: Forecasting CO2 Cavity Corrosion on Tubing of Gas Wells
Authors: Alsalman Malik , Nasizadeh Zoha , Hosseini Masoud M. , Samuel Robello
Published: September 2015

Well casings and tubing strings are subjected to severe corrosion because of their exposure to severe environments provided by corrosive fluids during production. The problem can be more challenging when dealing with deep formations at high temperature and pressure. The tubular string exposed to corrosion suffers from strong degradation that can lead to tubing burst and collapse. It is highly desirable to predict the threshold pressure for degraded tubing strength, and design the tubing strings with consideration of these corrosion effects. The objective here is to forecast the corrosion effect on tubing-strength degradation throughout the entire life of the well.

The worst-case corrosion caused by CO2 in gas wells has been considered. This type of corrosion causes pitting cavities, which reduces the tubing strength over time. The effect of possible cavity depth and diameter on the stress-concentration factor is considered as well. The pressure profile of the production has been coupled with the phase envelope of the fluid along the well to find the region of maximum CO2 condensation. Then the Dewaard et al. model of CO2 corrosion rate is used to find the growth of corrosion cavity at the depth of maximum CO2 condensation. Finally, the cavity size is applied to the stress concentration factor model to find the degradation of the steel strength during well production at this depth.

What makes this work unique is that it uses four different fields related to petroleum engineering, which are production, phase equilibrium, corrosion, and steel strength, to build a corrosion model that can be applied to various types of steel to predict the collapsing of the tubing during the production. Therefore, several collapsing or leaking problems can be prevented that consume both money and time. Also, this study can be expanded to include other corrosive factors and components, such as the pH of the fluids and H2S, which is a very corrosive component.
Successful Squeezing Operation of Magnesium Based Ultrafine Cement Through Wire Wrapped Screen With Mesh Size of 20/40
Authors: Karim Nurul Aiman , Ellis Todd B , Maluan Lilihani
Published: September 2015

Utilization of chemical treatment to isolate or shut off zone is not uncommon in this industry. Cement will normally be chosen as candidate to perform the job as it is more permanent and more economically effective. With recent advanced technologies, cement particles are now designed to be in smaller particles yet still be able to develop sufficient amount of compressive strength for effective zonal isolation and hydraulic seal. Magnesium based Ultrafine Cement System was chosen as chemical candidate to be used in Sarawak West Oil Field. The primary purpose of using this cement system is to penetrate through Wire Wrapped Screen with Mesh Size of 20/40 in the completion. The utilization of Ultrafine Cement in the operation was incorporated with Calcium Carbonate and Cement G slurries. Calcium Carbonate will act as the suspension fluid while Cement G slurry will be pumped to fill up the inside volume of Wire Wrapped Screen after Ultrafine Cement being pumped to occupy the outside volume of Wire Wrapped Screen. Compatibility test between Ultrafine Cement and the two slurries had been tested in the laboratory and it was reported that there was no significant change of viscosity value when they are mixed together. Application of Ultrafine Cement in Sarawak West Oil Field indicated that all Ultrafine Cement pumped during the operation was managed to pass through the 20/40 Mesh Size. Tubing Clearance Check (TCC) by Slickline showed high held up depth (HUD) but Coiled Tubing was used to run in hole to confirm on the HUD depth. It was reported that there was no significant weight loss when Coiled Tubing passing through Slickline HUD. Coiled Tubing stopped run in hole at Top of Calcium Carbonate to avoid disturbing the suspension fluid. Based on this situation, it is also known that there was no presence of Ultrafine Cement settle on top of Calcium Carbonate at all due to its efficiency in penetrating the Wire Wrapped Screen.
Offshore Project Risk Management Model (OPRMM) As a Tool for Efficient Field Development
Authors: Talipova Aminam
Published: September 2015

Risk Management approach is an essential part of the project. Large industries and particular companies incorporate RM Culture. Statistics shows, that companies with Project Management (PM) Structure reduce cost ineffectiveness up to 20%. In oil and gas industry PM Risk Analysis (PRMA) has been widely used for the last years. Various models and procedures have been developed to manage projects of different scale.

Nonetheless, Offshore Projects (OP) complexity, high uncertainty of technical, financial, market and government factors, as well as different sea conditions, still makes sense to improve general PRMA models according to the oil and gas OP features. Traditional RM tools and techniques are not appropriate to cope with complex projects in the Arctic. Companies will have to modify risk assessment process or look for new methods. The paper suggests OPRMM, where the attempt to implement PM tools and techniques together with mathematical modeling and expert assessment is made and institutional factors are included. Practically, it is founded on the comparison between offshore field development in the Barents Sea and the Kara Sea. The reason for research is debates around future Arctic oil and gas projects and their commercial potential. Several large projects with participation of major international companies in the Barents Sea and the prospectivity of the Kara Sea Projects in conditions of technology difficulties are under discussion and have not reached the investment project phase yet. OPRMM starts with identifying the key factors, which could affect offshore field development. Inside the investment regime modified real option value (ROV) model for OP is developed: stop option and scale transformation option. Basing on the binominal trees and Monte Carlo Simulation it is possible to see the perspectives of the OP at an early stage in the conditions of high uncertainty. Incorporating the ROV model into investment regime allows operator to choose the territory to explore.

The research shows, that offshore projects in the Arctic offshore is not only under the pressure of internal corporative factors, but also under influence of external institutional factors. New tools and approaches will be required in Arctic projects where no one wants to be looking in the wrong place.
Use of Novel Self-Healing Materials to Control Sustained Casing Pressure and Prevent Long Term Environmental Impact
Authors: Arif Khattak Mohammad , Jain Bipin , Al Kalbani Sultan , Ahmed Junaid , Arya Afrianto Agung , Qassabi Nabhan , Aghbari Salim , Salti Anwar , Rashdi Sami
Published: September 2015

PDO is the biggest Oil and Gas Producer in Oman drilling in several fields with a number of drilling and cementing challenges. One of the key challenges that the operator has started to encounter is sustained casing pressure (SCP) because of poor zonal isolation. Hydrocarbons are observed in B or C annuli and lab analysis confirms it is coming from one of the Limestone reservoirs. More than 4 wells that were drilled in 2012 and 2013 have been identified with SCP and others are being monitored. The drilling campaign in this particular field was halted because of SCP problems and failure to comply with government regulations. Expensive work-over operation had to be done to abandon the wells.

Owing to the fact that conventional cement systems and practices have proven ineffective, an innovative self-healing cement system was introduced. This system has the property of self-repair when in contact with hydrocarbons, seals any pathways and restores well integrity without any intervention thus providing long term zonal isolation. The system is placed conventionally in the annulus as part of the cement slurry and the healing material stays dormant till the time it sees the hydrocarbons that may flow through the cracks. Subsequently it expands and heals the cracks.

The self-healing cement system has been tried in four wells in the same field with excellent results. After more than one year of completion, no gas pressure has been observed in the annulus. The operator has standardized this system for this field for all future wells and plans to extend the use to other fields with similar issues.

This paper will cover details on the system, mechanism of work, validation process of the system, operational aspects and field implementation to elaborate how SCP problems can be overcome.
Intelligent Use of Big Data for Heavy Oil Reservoir Management
Authors: Popa Andrei S. , Grijalva Eli , Cassidy Steve , Medel Juan , Cover Andrew
Published: September 2015

In recent years, the application of Big Data technologies and associated analytics has enjoyed significant attention and has seen an enormous growth in the oil industry. This is due to exponential growth of both historical and real-time data being collected. In this article, we present examples of the successful application of these technologies for the management and optimization of large heavy oil reservoirs. These particular reservoirs present a very interesting, yet complex, challenge given the steam assisted gravity drainage recovery mechanism and the thousands of producers, injectors, and observation wells which generate terabytes of data on a daily basis. To handle all this large and high-dimensional information efficiently, we introduced new workflows consisting of operational domain data acquisition, data transfer to business domain, storage in accessible repositories, and ending with data consumption, quality control, visualization and analytics.

The paper summarizes how big data is aggregated into smart applications to monitor the reservoirs and observe steamflood recovery development. Examples of high definition DTS data integrated with completion, wellbore equipment, geologic markers, and real-time wellhead pressure showing reservoir heating and/or cooling are presented. Intelligent visualization tools and analytics, such as pattern recognition applied on static and dynamic subsurface data enabled superior heat management. A second example of high efficiency operations enabled by big data is the well integrity during cyclic steam operations. Pressure and injection rate data streams are integrated with analytics to monitor and identify abnormal operating conditions. Lastly, an example of facility reliability and production impact quantification is demonstrated through use of integration of surface system stream data and subsurface well information. The later led to significant business impact in terms of realized production and operation cost savings.

The examples presented in this paper demonstrate the business impact and value creation generated by efficient use of the Big Data technologies and associated analytics for heavy oil reservoir management and optimization. The workflows are now used in all Chevron heavy oil fields in San Joaquin Valley.
Non-intrusive Multiple Zone Distributed Acoustic Sensor Flow Metering
Authors: Finfer D. , Parker T. R. , Mahue V. , Amir M. , Farhadiroushan M. , Shatalin S.
Published: September 2015

The Distributed Acoustic Sensor (DAS) used here (Parker et al., 2012), allows both the amplitude and the phase of acoustic signals to be continuously recorded along a length of optical fiber. In this paper, non-intrusive flow metering based on the use of this sensor is performed for different pipe sizes and flow conditions. By wrapping a continuous length of fiber helically around the exterior pipe, the system measures the dynamic radial strain (hoop strain) along a pipe with a spatial resolution on the order of millimeters and a time resolution on the order of tenths of milliseconds. As a result, this implementation of the sensing system output makes it possible to visualize the generation and convection of eddies by using a waterfall plot of distance versus time. By analyzing the recorded data using a frequency-space transformation (f-k plot), it is possible to determine precisely both the speed of eddies, as well as the speed of sound.

This paper will present experimental results from single- and multi-phase tests to demonstrate the applicability of the technology to the monitoring of fluid velocity and the determination of flow composition. It will be seen that the system, which can be installed unobtrusively, is straightforward to apply for several types of commonly encountered flow regimes. Further, this paper will also consider several practical aspects regarding the installation and use of such a system in the oilfield. Finally, it will be shown how multiple monitoring zones can be incorporated using a single optical fiber. It will be seen that this system is non-intrusive and can be retrofitted to existing pipes to monitor the flow simultaneously at multiple locations for accurate flow profiling and characterization.
High-Performance Plug-and-Perf Completions in Unconventional Wells
Authors: McNelis Liam , Salt Warren , Scharf Thilo S.
Published: September 2015

An innovative new design of a perforating system for plug-and-perf completions in unconventional wells demonstrates that operations can be made more efficient, safe and reliable. Results from extensive modeling, testing and field tests demonstrate that the entire perforating process, including gun loading, arming, running, perforating, maintenance and disposal, is made more robust by eliminating traditional approaches to selective perforating, detonators, gun hardware and accessory equipment.

The new system optimizes perforating operations with fully assembled and ready-to-shoot gun modules delivered to the base or to the wellsite. An innovative integrated switch-detonator design replaces all wiring and crimping to eliminate human error and to significantly reduce the risk of inadvertent ignition or detonation. Arming a gun is now as efficient, safe and reliable as placing a battery in a flashlight. True intrinsically safe microprocessor switch-detonators require no wiring so they achieve measurably higher reliability than standard separate switch-detonator combinations, and they are immune to potential hazards that can impact standard selective perforating equipment in use today. Surface test equipment detects any malfunctions before running in hole, and the software allows continuous monitoring of all downhole components until initiation and in between shots. All wellsite operations can continue without interruption, and full selectivity, communication to all detonators, stage-skipping and gun redundancy are enabled for the most complex completions. Gun length, shot phasing, shot density and charge type are fully customizable with injection-molded gun parts that do not create unwanted debris after perforation.

The system design targets a 10X improvement in reliability over existing plug-and-perf equipment. Wireline service companies traditionally experience reliability in unconventional well perforating ranging from 30 runs/misrun to 100 runs/misrun. Early results suggest the new system may exceed 1,000 runs/misrun. By reducing the risk of mishaps, misruns and misfires, rig time is saved, frack costs are lowered, and every stage can be perforated to contribute to higher well productivity.

Field tests of the new design demonstrate the advantages of a fully integrated perforating gun system. The new technology leverages innovative component-level features and a system design approach to produce a perforating system that eliminates many of the causes for misruns, increases simplicity and safety of operations, and delivers higher well productivity.
Differentiating Open Natural Fractures From Healed Fractures Using The New, High-Definition Oil-Based Mud Microelectrical Imager – Case Studies From Organic Rich Shales
Authors: Li Bingjian , Chen Yong-Hua , Gawankar Kiran , Miller Camron K. , Xu Weixin , Laronga Rob J. , Omeragic Dzevat
Published: September 2015

Distinguishing open natural fractures from healed fractures has been a significant challenge in shale formations drilled with oil-based mud. Ultrasonic imaging tools can locate open fractures, but such data is seldom acquired due to concerns related to the effects of heavy mud and, in high-angle wells, operational efficiency and tool eccentralization. Until now, the microelectrical image tools in the market were not capable of differentiating open fractures from healed fractures in oil-based mud.

A new, high-definition oil-based mud microelectrical imager has been deployed that operates at high frequencies and provides images with high borehole coverage. This new tool can identify natural fractures, sub-seismic faults, and other geological features in the reservoirs. In addition to high-resolution images of formation resistivity, an advanced inversion processing can be applied to generate resolution-matched images of the quantified standoff between each sensor in the array and the borehole wall. Such standoff images are of special value for differentiating open fractures from healed fractures. The use of these standoff images are presented in several recent case studies from U.S. shale plays. In the first case study from a pilot shale well in the northeast, natural fractures are identified on the new microelectrical imager and then further interpreted as open, partially open or healed fractures based on the inverted standoff images. Such open fracture interpretation has been validated by ultrasonic image data from the same well. In the second case study from an Eagle Ford Shale lateral in south Texas, both natural fractures and sub-seismic faults were detected. Interestingly, one of the interpreted open faults based on standoff images was even evident on dynamic pressure data in a monitoring well nearby during the stimulation process.

Natural fractures can impact the shale reservoir quality, completion quality, or both, depending on the fracture types and intensity. Therefore, it is beneficial to have a reliable dataset to sort fractures by their type: open, partially open and healed.
Optimizing Separation Efficiency Of Produced Water Tanks By Installing CFD Designed Internals
Authors: Trofaier Nikolas , Weilhartner Alexander , Puchner Bernhard , Konieczny Jaroslaw , Friedl Nikolaus , Kuemmel Georg , Perez Oscar Alberto , Steinbrugger Anne , Markl Richard
Published: September 2015

Efficient produced water management has been a growing concern in the oil and gas industry over the last decades. Water cuts have risen and more oil fields are maturing. Therefore growing volumes of produced water have to be handled every year. The most common disposal option is reinjection into the reservoir. In order to reinject produced water it has to be treated. Produced water tanks (PWT) are usually applied as first stage separators in water treatment plants. The oil-water separation efficiency of PWTs can be improved by optimizing tank internals to reduce the load on downstream treatment units. This study shows the results of a Computational Fluid Dynamics (CFD) based optimization approach for various water tanks in mature oil field environments.

The concept centers on the induction of a tangential liquid movement in PWTs to maximize residence time for a given volume of water and to reduce short-circuiting. In order to show the benefits of such a setup, an existing tank was upgraded with CFD designed internals. The separation efficiency of the tank was recorded prior to and after installing the internals. The results showed that the average residence time could be extended eightfold.

Based on the initial experience and additional simulation work, the internals concept was adapted and improved for several new tanks. These tanks are currently under construction and first field results will become available in 2016.
The Effect of Bit Type on Reactive Torque and Consequent Toolface Control Anomalies
Authors: Ledgerwood L. W. , Spencer Reed W. , Matthews Oliver , Bomidi John A. , Mendoza J. A. , Hanson Jonathan M.
Published: September 2015

The oil and gas drilling industry has developed a large body of knowledge about methods for drilling directional wells with steerable motors. Experience indicates that more aggressive drill bits are harder to steer. This is commonly attributed to the fact that bits with higher aggressivity produce larger torque changes for a given change in bit weight. The actual mechanics, however, of toolface disorientation during slide events is poorly understood. This paper reports on tests conducted on a full-size drill rig aimed at understanding the mechanics of toolface control. Toolface orientation and other data were measured downhole at 100 Hz. Nine different bits ranging from PDC to hybrid to roller-cone bits were tested on a motor/AKO BHA in slide mode. These tests confirm the common industry notions about the effect of aggressivity on toolface control. They also show that angular motion of the BHA while sliding is overdamped. Toolface orientation consequently follows the average of the torque signal generated by the bit. Furthermore, the toolface orientation is more easily disoriented by a torque signal at a frequency near or less than the natural frequency of the drillstring. PDC bits excite this more readily than bits with rolling cones. We also identify a toolface disorientation anomaly which we call a fast torque anomaly (FTA). FTAs occur because the bent motor/AKO has a preferred angular orientation in the borehole. FTAs have not been previously recognized, probably because they are not identifiable in mud-pulse signals. A BHA suffering FTAs would simply appear as a chaotic and profound loss of toolface control in mud-pulse data. Hybrid and roller-cone bits caused fewer FTAs than PDC bits.
Radio Frequency Identification (RFID)-Enabled Circulation Sub Precisely Spots Loss-Circulation Material in Critical Interval
Authors: Valverde Eddie , Reitsma Rienk , Hutchings Travis
Published: September 2015

Taking fluid losses in a drilling operation is common practice. Pumping loss-circulation material (LCM) to control drilling fluid losses to the formation is part of the overall solution. Precisely spotting the correct volume of LCM and protecting sensitive directional tools in the bottomhole assembly (BHA) has proven to be a considerable challenge.

Recently in a critical offshore well in the North Sea, the 6.5 intermediate section was drilled to 10,446 feet through a soft, porous limestone formation. In addition to the propensity of the chalk formation for seepage, a pre-existing natural fault was also present. The drilling fluid used to drill this section was 8.7-ppg paraffin- and mineral-based mud. Factors key to controlling losses were LCM displacement in precise intervals of the section and timely delivery of the material into the well annulus through a diverter circulation sub. High flow rates and minimal differential pressure at the tool were key to the mud program.

Because the RFID-enabled diverter circulation sub was capable of being selectively opened and closed using specifically programmed transponders, it did not require a ball seat or mechanical indexing system. This feature, coupled with the extra-large total flow area (TFA) and integrated flapper system of diverter circulation sub, allowed precise and timely LCM pumping while completely protecting the measurement-while-drilling (MWD) and rotary steerable (RSS) systems from damaging debris.

A total of 29 pills were pumped in the 14-day period that it took to drill the section. The circulation sub was strategically opened and closed in the diverting mode during this pill and LCM pumping program to control losses and allow the operator to drill ahead. By using an RFID-enabled circulation sub specifically designed to displace heavy pills and LCM, the operator was able to control losses, maintain proper hydrostatic pressure, and reach total depth (TD).
Microseismic-Derived Expected Ultimate Fracture Half-Height Above/Below Wellbore in Unconventional Stimulated Reservoir Volume in a Multi-F ractured Horizontal 10 Well Pad - Canadian Horn River Basin Case Study
Authors: Virues Claudio , Budge Jessica , Lunen Eric von
Published: September 2015

Over the past decade, microseismic (MS) monitoring has become the primary approach used to gain an in-situ understanding of the rock's response during stimulation. Recently, the utilization of downhole monitoring of treatments has provided an opportunity to investigate ways by which these fractures develop by examining microseismic events recorded during stimulation. In the Horn River, geophysicists and engineers used microseismic field data and its interpretation to constrain reservoir models. Generally, it has been observed that fracture height, width and length vary from formation to formation.

In the presence of uncertainty in reservoir models, input data is required for determining the best estimate of a value, and probabilistic methods are used. Risk analysis is a technique used to quantify the impact of uncertainties on output variables, and to determine a range of possible outcomes. In this paper we use Monte Carlo simulation and probability density functions (PDFs) that describe likely values of fracture half-height as an input parameter into reservoir models. PDFs and Cumulative Distribution Functions (CDFs) are used to provide realistic estimates of stimulation parameters, such as stimulated reservoir volume.

Microseismic interpretation of events provides an upper bound value for fracture half-height in unconventional shale gas reservoirs. Its CDF for each well on a multi-fractured horizontal well pad provides a better understanding of what the ultimate fracture half-height could be after pressure depletion, and what the resulting implications for well spacing/ placement in pad design are. This facilitates a probabilistic approach to production forecasting and reserves estimation, and allows us to calculate a robust estimate range of estimated ultimate recovery (EUR) and recovery factor (RF). This approach differs from previous work that is based on strong collaborative work between geophysicists and engineers.

This paper contributes technically to the knowledge of the unconventional shale oil and gas industry by constraining analytical models that can be used as a quick look/ first pass into numerical simulation, and as estimators of production forecasts and different reserves categories. Furthermore, some of the design considerations of the multi-well pad, in addition to surveillance data – such as production logs, chemical fluid and radioactive tracer – will be addressed, concluding with a discussion of the results.
Sand Transport in Stratified Flow in a Horizontal Pipeline
Authors: Dabirian Ramin , Mohan Ram S. , Shoham Ovadia , Kouba Gene
Published: September 2015

The entrainment of sand in crude oil occurs during production from reservoirs with low formation strength. The stationary sand bed at the pipe bottom can cause operational problems such as production decline, excessive pressure loss, equipment failure, erosion and corrosion. Sand deposition can be managed by operating above critical sand deposition velocity, which is the velocity that keeps particles moving all the time at the pipe bottom. A comprehensive analysis of sand flow regimes in stratified flow in horizontal pipeline is presented here, which is a novel contribution in this paper. Also, the effect of concentration on the sand flow regimes and identification of critical sand deposition velocities for various concentrations are investigated in this paper.

The understanding of sand flow regimes in pipelines for any given set of operational conditions is important to identify the nature of particle interaction and movement. Experimental studies have been conducted at stratified flow regime with air-water-glass bead at relatively low sand concentrations (<10,000 ppm). The effects of different experimental conditions such as gas velocity, sand concentration, and particle size have been investigated in this study. Six main sand flow regimes in horizontal air-water flow are identified, which can be distinguished visually: fully dispersed solid flow, dilute solids at wall, concentrated solids at wall, moving dunes, stationary dunes and stationary bed. Therefore, the critical sand deposition velocities are determined based on the transition between moving (concentrated solids at wall/ moving dunes, as appropriate) and stationary (stationary dunes/bed, as appropriate) sand particles. The experimental data shows that with small particle size, the critical sand deposition velocity is almost independent of concentration, while with bigger particle sizes, the critical velocity increases with the concentration.
Measurement of Key Shale Petrophysical Properties
Authors: Zamirian Mehrdad , Aminian Kashy , Ameri Samuel
Published: September 2015

Even though the advances in hydraulic fracturing and horizontal well technology have unlocked considerable reserves of hydrocarbon contained in shale formations, quantification of the key petrophysical properties in shale reservoirs still remain challenging. The unconventional formations such as shales typically have permeability values in nano-Darcy range. It is not practical to measure the permeability of the shale samples by conventional steady state techniques because of very low flow rates and length of time required to reach the steady state condition. Therefore, unsteady state methods such as GRI and pressure pulse decay which have been extensively used to estimate permeability of the shale samples. However, the measured permeability values for similar samples by these techniques can differ by 3 orders of magnitudes. This large margin of uncertainty and non-uniqueness of the results can be attributed to the interpretations of the data obtained from transient techniques and reproducibility problems. Furthermore, the unsteady-state measurements are not performed under the reservoir effective in-situ stress and temperature which introduces more limitations.

This paper describes the design, construction, and application of a laboratory set up and test protocols for accurate and repeatable measurements of the rich organic shale porosity, permeability and sorption characteristics under reservoir stress conditions. The near steady-state measurements can be performed in minutes up to hours, depending on the characteristics of the sample. This allows the permeability measurements to be performed as many time as need to produce repeatable results. Furthermore, the absolute permeability of the sample can be calculated by applying the gas slippage (Klinkenberg) and/or gas double-slippage corrections. The monitoring of the flow rate during the experiment allows to determine when the sample is fully saturated (adsorbed or desorbed). Therefore, there is no need for gas sorption correction.

The paper also present the results of measurements on several Marcellus shale sample which clearly indicate that shale's porosity and permeability to a larger extent, are sensitive to stress and the stress impact on permeability is non-reversible. This could be attributed to flow of gas through micro-fractures, which do not contribute to porosity significantly. In addition, the analysis of the measurement results indicated that only gas double-slippage corrections can provide reliable values for the absolute permeability of the sample. The sorption characteristics, although not the primary objective of the measurements with laboratory setup, are compatible with published values.
Estimating Permeability Anisotropy From Downhole Distributed Temperature Measurements
Authors: McCabe K. , Horne R. N.
Published: September 2015

In many reservoir studies, anisotropic permeability is often ignored or considered to have only simple relationships. Often, permeability anisotropy is modeled only between the vertical and horizontal directions, while permeability values in a horizontal plane are considered equal. In reality, the depositional history of the reservoir results in more complex behavior. Knowledge of the permeability anisotropy has important implications in several types of devlopment scenarios, thus it is important to have accurate estimates of these directional permeability values. For example, a partially-penetrating well that allows for vertical flow at depths below the completed interval requires knowledge of the vertical to horizontal permeability anisotropy. As another example, improved estimates of horizontal permeability anisotropy would have significance for directional drilling design.

In this work, the utility of temperature data as a matching parameter was investigated to estimate these directional permeability values. The study utilized a full-physics, thermal reservoir simulator and a nonlinear, least-squares regression algorithm for parameter estimation. By modeling block temperatures near the well, the study attempted to replicate the temperature data gathered from Distributed Temperature Survey (DTS) tools which use fibers to measure temperature history at the well. Using this method, the permeability anisotropy in two scenarios (vertical-horizontal and horizontal-horizontal) was estimated successfully with a high degree of accuracy. Even with the addition of synthetic noise to the temperature signal, the regression was robust in estimating the values successfully in the majority of anisotropy scenarios that were tested.
Quantifying Flow Rates From Temperature and Pressure Measurements in Deepwater Wells
Authors: Venkatraman A. , Hasan A. R. , Sohel R. H. , Patni S. , Elshahawi H. , Yousif M. H. , Abbasi F. R.
Published: September 2015

Quantifying production from different producing reservoirs is critical, especially in deepwater fields where interventions are either not possible or prohibitively expensive. In this study, a model is presented for a well producing from multiple reservoir sections to estimate flow contribution of each reservoir section using temperature and pressure measurements. The production from a well is modeled as a series of producing (vertical flow along with radial flow from a producing reservoir section) and non-producing (only vertical flow through the production tubing) zones. In addition to the sand face temperature measurements, surface temperature, total surface flow rate as well as pressure and temperature measurements in the producing tubing are used as input to the model. The temperature measurements in non-producing sections are critical to quantify flow from producing sections. These measurements are used to obtain thermal properties of the reservoir and particularly useful to quantify error in the flow rate estimates obtained from the model. The presented model can be adapted to any well producing from multiple reservoir sections. The temperature data can be used to diagnose problems with producing zones as well as identify locations of producing and non-producing zones as the well continues production. The model can also help determine the location as well as the number of temperature and pressure sensors required to estimate flow rates from individual reservoir sections in a specified error range. This is particularly useful for reservoir sections, which are difficult to characterize. The sensors along with the model have the potential to become an integral part of production monitoring for reservoir management.
Novel Uses of Multifinger Calipers Utilizing 3-D Visualization: Case Studies From the North Slope of Alaska
Authors: Burton Joey , Julian Jennifer
Published: September 2015

Historically, multi-finger calipers have most often been considered tools for assessing internal corrosive damage to tubing and casing strings or evaluating wellbore obstructions. With the development of high resolution digital tools in the early 1990's and subsequent development of 3D caliper data viewing utilities at the turn of the century, these tools have expanded their roles into more complex well work diagnostic operations. On the North Slope of Alaska, the practice of exploiting new pay zones by drilling and completing side-tracks from existing well bores has grown significantly as the fields mature. The development of coiled tubing drilling and its application to thru-tubing side-track drilling has made a sizeable contribution to the battle against production deline on the North Slope. The practice of utilizing a ‘used’ wellbore to drill and complete a new well brings an increased need for diagnostics in assessing the integrity of existing completion components, evaluating new drilling practices and confirming the integrity of new completion designs.

On Alaska's North Slope, multi-finger calipers have been used extensively in the optimization of thru-tubing side-track drilling and completion operations. Before any drilling begins, they are used to evaluate existing well bores for sufficient integrity to support new drilling/completion operations and cost effective production of the new pay zone. During drilling operations, they are often used to confirm borehole geometry and integrity prior to moving forward with re-completion procedures. Once the new completion components have been installed, multi-finger calipers are used to confirm and document the proper placement and integrity of the new completion components. The development of 3D Visualization tools for multi-finger caliper data has played a key role in extending the utilizing these tools to complex drilling and completion diagnostic applications. The application of 3D multi-finger caliper data visualization toward advanced drilling and completion diagnostic needs on Alaska's North Slope are discussed in this paper.
Maximizing Drilling Sensor Value through Optimized Frequency Selection and Data Processing
Authors: Baumgartner Theresa , Oort Eric van
Published: September 2015

Downhole high frequency sensors are heralding the era of big data in drilling and have already shown potential to significantly push the limits of drilling performance. Downhole data transmitted in real time can be used to optimally select parameters during drilling and optimize off-bottom operations. The wealth of information from retrieved memory data gives immediate insights in well specific performance limiters.

Nevertheless, downhole data is not yet used to its full potential, as the industry is only just beginning to make sense out of the many gigabytes of recorded data. Often, measurements cannot be unambiguously linked to specific downhole dynamics and their respective dysfunction. Most valuable information is lost directly at the sensor when processing (e.g. averaging) is not done appropriately. In other cases, huge amounts of high frequency data are transmitted and stored without providing much useful information. Large data volumes quickly reach the limits of transmission broadband and memory capacities of downhole tools and pose huge challenges to drilling data analysis and data integration.

As a solution to handling the rapidly increasing amounts of drilling data, this paper proposes a value of information based approach to downhole sensors, data processing and analysis. An extensive set of field data from multiple operations is used to demonstrate the interrelation of dynamic effects and their impact on downhole sensor measurements. Different requirements on sensor type and collection frequency apply to identify different types of drilling performance limiting dysfunction, such as vibrations, well tortuosity or cutting accumulations due to poor hole cleaning.

It is shown that the analysis of frequencies is key to separate multiple downhole effects wrapped into one measurement. For each prominent type of dysfunction, minimum data collection frequencies are specified which allows for the differentiation of unimportant noise from valuable drilling performance limiters. These insights are used to describe more effective methods of data processing, by cross-linking information from multiple sensors.
Evaluation of Solid Particle Erosion Equations and Models for Oil and Gas Industry Applications
Authors: Arabnejad H. , Mansouri A. , Shirazi S. A. , McLaury B. S.
Published: September 2015

The goal of this work is to provide an evaluation of the uncertainties in the calculation and measurement of erosion caused by solid particles that are entrained in the produced fluids in the oil and gas industry. Erosive damage is of great importance in production and transportation facilities, and it has been studied widely utilizing experiments or modeling approaches. The experimental setup used by researchers and uncertainty in determining the particle impact condition were key factors in the erosion measurement results and corresponding derived models. The effect of these parameters is studied in this work, and a guideline is provided to address the resulting error. In order to address the effect of particle velocity on erosion, Particle Image Velocimetry (PIV) is used and velocity distribution is obtained. The effect of particle velocity is analyzed in both experiments and erosion models. The erosion calculations by Det Norske Veritas (DNV) and Erosion/Corrosion Research Center (E/CRC) models have been compared to experimental data collected at the University of Tulsa and available data in the literature. A semi-mechanistic erosion equation which has been developed for some alloys that are being used extensively in the oil and gas industry is implemented in the CFD simulations. Based on the power-law dependency of erosion models on particle impact velocity, it is shown that uncertainty in the determination of particle velocity is propagating to the measured material losses in the experiments or in the predicted values in the erosion models. The erosion model predictions showed general agreement with experimental data in the literature for a wide range of conditions, but over predictions and under predictions have been observed which are due to the uncertainty in the measurements or erosion modeling.
Australia's First Build Own Operate CSG Produced Water Treatment and Beneficial Reuse Project
Authors: Le Hiep , Chalmers Scott
Published: September 2015

The coal seam gas (CSG) exploration and appraisal activities by Santos in Narrabri, New South Wales (NSW), Australia results in produced formation water (PFW) that is stored in specially constructed double lined ponds. The ponds also store legacy brine from desalination of PFW from previous exploration activities. Santos is seeking to treat this water for beneficial reuse in irrigation, dust suppression, construction and drilling, and emergency firefighting purposes.

Santos have outsourced this requirement to Osmoflo under a hybridized build, own and operate model, which includes the design and delivery of a water and brine treatment plant (WBTP), as well as all associated infrastructure (power generation, transfer pipelines etc.), construction management and specialist operation and maintenance services for 3 yrs initially, with a possible extension to 5 yrs.

The WBTP is containerized to allow demobilization and future possible re-deployment, and to find an appropriate balance between the often competing drivers of the projects technical objectives, and the commercial requirements of delayed and minimized capital expenditure.

Key technical requirements include: Ability to handle a very wide range of PFW salinities and solids from different sources.Ability to provide 1 MLD irrespective of above water quality and chemistry, in order to maximize disposal opportunities via irrigationAbility to concentrate the PFW and produce a final brine in excess of typical brackish and seawater desalination system in order to provide maximum ‘ullage’ in the fixed volume ponds.Ability to dewater the solids from filter backwashing for off site disposalStrict environmental performance requirements for absolute containment of all PFW, permeate and brine.

The salinity of the PFW and legacy brine ranges widely from 18,000 to 51,000 mg/L. This needs to be desalinated to produce irrigation quality treated water of salinity <600 mg/L. The water sources have algae counts up to 8.8 million cells/mL. In the design process, Osmoflo has selected disc filtration followed by a microfiltration (MF) system to pre-treat the water suitable for treatment through reverse osmosis (RO). The disc filters and microfiltration have proven successful in treating other CSG produced formation water as well as water with high algal counts.

The RO system has been designed with a two stage configuration with an interstage booster pump to allow variable water recovery from 55 to 70% depending on the PFW salinity. The brine from the RO system is further concentrated through Osmoflo's Brine Squeezer (OBS) process which is an innovative, cost effective, ultra-high recovery RO process. The Brine Squeezer process is designed to concentrate the brine to a salinity >90,000 mg/L in order to minimize the brine volumes. The final concentrated brine will be stored in the ponds.
Dual Reaming Reduces Vibration in Deepwater Well
Authors: Goodwin Alex , Salminen Chuck , Valverde Eddie
Published: September 2015

Simultaneous drilling and enlargement is common in deepwater Gulf of Mexico projects. It controls equivalent circulating density, manages pore pressure anomalies, and ensures that casing strings and liners reach total depth (TD). Common hole-enlargement-while-drilling (HEWD) bottomhole assemblies (BHAs) place a concentric hydraulic underreamer above the rotary steerable system (RSS) and measurement-while-drilling/logging-while-drilling (MWD/LWD) package. Although this placement is effective, it could leave up to 200 ft (61 m) of under gauge rathole at TD, which often leads to a dedicated trip to eliminate the rathole. This underreamer placement with the bit off bottom also has limited underreaming capabilities because of vibration caused by drill string instability. These vibrations typically make underreaming an existing pilot hole more difficult than simultaneous drilling and reaming.

On a job for a sidetracked well in the Gulf of Mexico, a drilling team had challenges in a 12 1/4- × 14 1/2-in. section. The team encountered significant vibration and torque when underreaming 423 ft (129 m) of an existing 12 1/4-in. pilot hole in a salt section. After this operation proved unsuccessful, due to low rate of penetration (ROP) caused by severe torque spikes and high shocks and vibrations, the team opted for an alternative solution to achieve the section objectives.

The team designed a unique BHA that included two intelligent underreamers. The first placed above the MWD assembly, and the second placed below the MWD assembly. Historically, placing underreamers below the MWD package and near the bit creates problems because the inside diameter (ID) of the MWD/LWD tools restricts balls that activate the underreamer, and flow-operated underreamers can prematurely activate or fail to activate.

In the new dual-reamer design, radio-frequency identification (RFID) technology provided the capability of activating and opening each underreamer and underreaming with both simultaneously. Wiring through the underreamer below the MWD package connected the rotary-steerable and MWD tools for communication.

The team ran the RFID underreamer below the MWD/LWD package and activated the cutter blocks at the correct depth. The team used both reamers concurrently to ream the 423-ft (129-m) section and then tripped into the hole using the upper reamer to continue drilling the below-salt formation. The operation continued as planned until 500 ft (152 m) before the planned well depth. At that point, downhole problems resulted in losing the BHA in the hole, cementing the openhole interval, and sidetracking the well.

The innovative dual-reamer design delivered a stable BHA to enlarge a wellbore section in one run, which could not have been done using a conventional ball-drop underreamer and BHA design. The drill string operated at 15,000 ft-lb (20,337 N∙m) less torque spikes than with the previous design.