Downhole Monitoring Research Articles

Downhole Measurement and Monitoring Lead to an Enhanced Understanding of Drilling Vibrations and Polycrystalline Diamond Compact Bit Damage

Summary Since backward whirl was discovered as a severe cause of polycrystalline diamond compact (PDC) bit failure, the oil and gas industry has made great strides toward creating whirl-resistant bits and operating practices. But is whirl still the major cause of PDC bit damage in conventional rotary applications? This paper reports on a recent field study in which downhole vibrations were measured by use of a newly available in-bit vibration-monitoring device. The focus of this study was to understand the primary source of bit damage. In addition, four wells were also drilled by use of a research drilling rig in Oklahoma. In these tests, the PDC bits, bottomhole assemblies (BHAs), and operating parameters were varied to document their effect on downhole vibrations. In these four wells, vibration measurements from the new in-bit measuring device were validated against a commercially available and industry-proven measurement-while-drilling (MWD) vibration-monitoring service. The results of this study indicate that the most common field vibration in hard-rock vertical conventional rotary drilling is stick/slip, not whirl. In field tests, stick/slip was observed almost exclusively. For typical field applications with a surface rotary speed of approximately 70 rpm, the team measured a peak downhole rpm as high as 500 during the slip phase. Stick/slip was identified as the primary cause of bit damage in these applications. Lateral vibration occurring during the slip phase correlated well with the observed damage and is proposed as a new mode of damage during stick/slip. The characterization of the lateral vibrations coupled with stick/slip is presented on the basis of downhole measurements.

Real-Time Optimization of SAGD Operations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 157923, ’Real-Time Optimization of SAGD Wells,’ by Luis E. Gonzalez, SPE, Peter Ficocelli, SPE, and Tad Bostick, SPE, Weatherford, prepared for the 2012 SPE Heavy Oil Conference Canada, Calgary, 12-14 June. The paper has not been peer reviewed. The steam-assisted-gravity-drainage (SAGD) process along with an efficient steam-use process can reduce production costs and increase the oil-recovery rate. The use of real-time downhole monitoring is an effective approach to achieve this optimization. The use of downhole distributed-temperature sensing (DTS) and array-temperature sensing by use of fiber-optic technology has led to instrumented wells that enable data access on a real-time basis, leading to better control of operations, and to optimizing the steam process. Also, fiber-optic technology enables measuring pressure and temperature over the same fiber and in close proximity along the wellbore. Introduction At reservoir conditions, bitumen is essentially immobile, and recovery of these highly viscous fluids requires viscosity reduction, often by applying heat. The SAGD process is an effective recovery method for heavy oil and bitumen. The SAGD process typically uses two parallel horizontal wells that normally are separated vertically by approximately 5 m. The top well is the steam injector, and the bottom well is the producer. As steam is injected, a steam chamber will grow around and above the injection well. Despite its effectiveness, the SAGD process has many economic risks including a high initial investment for constructing the surface facilities and uncertainties related to product prices. Displacement efficiency is a critical factor in controlling oil recovery from the steam chamber, and, although increased volumetric sweep is beneficial, the chamber-growth rate greatly affects the rate at which the displacement efficiency increases in the steam chamber. Increasing the volume of the steam chamber too quickly may decrease the effectiveness of the SAGD process. Uniform distribution of steam along the entire length of the wellbore could lead to a more-uniform steam-chamber growth, making the entire length of the well productive and developing optimum performance of a SAGD well pair. Traditionally, the SAGD injection well is completed with dual injection strings (one injection string ending at the heel and the other injection string ending at the toe) and the production well is completed with a slotted liner, as shown in Fig. 1. Steam distribution along the well is governed by different factors. The most important factors include pressure in the injector and producer wells, fluid-flow regime, fluid velocity, wellbore trajectory, and heat loss along the length of the wellbore. A new well/injector configuration is proposed that includes steam diverters, inflow-control devices, centralizers, fiber-optic pressure gauges, a fiber-optic DTS system, and control lines. An inter-mediate configuration could be the traditional dual string with the addition of temperature and pressure measurement by use of fiber-optic technology to help control the shape of the steam chamber.

Downhole Gauges Meet Challenges of Operating Beside ESPs in HT Reservoir

Technology Update Talisman Energy needed to enhance its continuous downhole monitoring capability at the Gyda field offshore Norway with a system that could perform in high-temperature (HT) conditions and operate beside electric submersible pumps (ESPs) in two oil production wells. Situated in the southern Norwegian Sea 270 km from Stavanger, Gyda is a mature field in which production peaked in 1995. To address the increasing water production and decreasing reservoir pressure, the company installed ESPs in the completion of new wells A-19A and A-26 in 2011. Estimated field production for 2011 was 8,000 BOPD, according to the Norwegian Petroleum Directorate. The field’s production license was recently extended to 2028. Challenges for New Monitoring System The Gyda field has an extensive permanent downhole monitoring network that tracks information on individual well conditions, such as temperature and pressure. Through sensors, gauges, and other downhole operating equipment, Talisman can monitor and, if necessary, maintain pressure; control each well; and optimize field production. However, adding monitoring systems to the A-19A and A-26 wells presented special challenges. The systems, which would need to monitor well zone conditions and the ESPs to ensure their function at the optimum points of their pump curves, would face reservoir temperatures as high as 160°C (and pressures as high as 300 bar). The HT environment can put enormous stress on instrumentation and impair its ability to generate reliable data. The standard gauges designed for the ESPs were not qualified to operate at the higher temperature levels found in the Gyda reservoir, thus further justifying the need for enhanced permanent monitoring. Another challenge was that the new downhole monitoring systems would have to operate effectively next to the ESPs. These pumps require large amounts of power, which is transferred downhole on a three-phase cable. This cable runs alongside the ESP cable and is susceptible to noise disturbance from the pumps’ motors and variable speed drive (VSDs). The VSDs—at 12 and 24 pulse, for example—can cause total harmonic distortion. This can be induced onto the downhole gauge control lines and interfere with downhole communication and gauge electronics, particularly during an ESP startup when the drive current can be six to eight times the normal operating current.

Research on the Key Technology of Exploiting and Waterflooding in One Well with ESP

The waterflooding development of Oilfield fringe area and scattered blocks are restricted by the existing pipe network design and pipeline transportation distance and so on. In order to improve the development effect of these blocks, by using advantages of ESP including high head, range capacity and mature technology, technology of exploiting and waterflooding in one well with ESP was discussed. Then, some key problems were settled such as sand prevention, sealing, downhole monitoring of process parameters, structure design and so on, and three process schemes were summarized including exploiting the upper layer and waterflooding the lower layer, exploiting the lower layer and waterflooding the upper layer and downhole pressurized injection. The technology proposed by this article has achieved good results proved by field applications. The success of the technology provides an economical and reliable energy supply technology for oilfield development, and has a broad market prospect.

Technology Focus: Mature Fields and Well Revitalization (January 2013)

Technology Focus Revitalization of mature fields holds the promise of lengthening the economic life of an asset years into the future. It has been demonstrated that significant value can be found in extensively produced mature fields. The characteristics of successful projects typically begin with a coherent exploration and production strategy that integrates elements of technology, personnel, and process. This collective approach not only allows the operators to combat the declining production levels but also brings new opportunities and adds value to the mature fields. The number of key enabling technologies in the revitalization toolbox is growing. For instance, new advances have been made in reservoir characterization, reservoir simulation, downhole monitoring and surveillance, multilateral drilling and completion, and production-enhancement techniques. However, each mature field has unique characteristics and often presents distinctly different challenges. It takes a concerted effort to integrate the right process, the right technology, and the right team to reduce risks and successfully execute a plan to revitalize an aging field. The availability and proper interpretation of existing data or ability to obtain quality data also reduces risks. Data management can be a key factor in the successful evaluation to revitalize a mature field. Economic constraints may limit actual data collection, thus concerted efforts must be made to leverage prior experience and knowledge. The development of new fields may undermine efforts to improve the recovery factor of mature fields. Nevertheless, revitalization projects are being implemented continuously worldwide, partly because the risks involved could be lower than those for developing new fields. Furthermore, the upside of preserving the use of existing infrastructure for revitalization purposes can be especially appealing. It is also worth mentioning that many of the same approaches and techniques can be shared between projects of exploration and revitalization. Papers selected for this month’s feature provide useful information on strategic planning, multidiscipline approaches, and use of enabling technology. All are useful for investigating potential solutions, narrowing down options, minimizing risks, and executing field-development plans. These papers and cited references also validate and confirm the continuous worldwide focus on improving hydrocarbon recovery from mature fields. There is much that can be learned by reviewing the lessons learned in the selected papers. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 151193 Near Field Developments With an Upgraded Brownfield Platform Rig: Sharing the Learning From a Three-Well Extended Reach Drilling Program by Miguel O. Mota, ExxonMobil, et al. SPE/IADC 151202 Regeneration of First-Generation Subsea Fields: The Challenges of New Wells in Old Infrastructure by Sean Stright, ExxonMobil, et al. SPE 145567 Reassessment of Reservoir Dynamic Behavior To Assist the Fourth Drilling Campaign in Mature, Geologically Complex North Sea Field by I. Valko, Total, et al.

Analysis and Design of Monitoring System in Coal Mine Based on Internet of Things

Perceived work environment in coal mine is part of the intelligent management of modern mine. Based on the existing backbone network, combined with the Internet of Things technologies, the architecture and functionality of the downhole monitoring system are presented. Hardware design of sensors and the principle of downhole location are analyzed. Describe the system features of anti-interference, higher warning level, high work efficiency. For receiving the data of downhole environment and location of workers, managers can carry out intelligent management and decision-making in emergency rescue and production decisions.

Technology Focus: Sand Management and Frac Pack (October 2012)

Technology Focus Production from challenging environments is fast becoming the norm for the oil and gas industry. We increasingly drill long horizontal sections in high-pressure/high-temperature reservoirs, deep and ultradeep water, and unconsolidated, depleted, and narrow-margin fields. With the cost of each well often exceeding USD 250 million, there is very little margin for error in designing and placement of the completions to avoid sanding-related issues and costly workovers. Novel materials such as light and ultralight proppants and shaped memory polymers, cutting-edge technologies, and robust hardware are all important elements for meeting the ever-growing challenges. Meticulous planning, bench testing, and field validation form a prerequisite for cost-effective and safe execution. Effective research and development (R&D) efforts and close cooperation among academia, R&D services, and industry experts (operators) pave the way for a technically successful and economically viable exploitation of our depleting reserves. One should also spend the time and effort to improve understanding of rock behavior in its in-situ stress environment, as well as accurate characterization of the unique stress conditions in the field. A mechanical Earth model satisfactorily calibrated to the drilling events and geologically consistent with the stress environment is often required to model and test various possible sand control methods and their economics accurately. Despite these efforts, it may not be possible to completely avoid sand production and its detrimental effects. Detecting and monitoring sand production with downhole monitoring tools, knowing the limits of effective sand management, and staying within those limits can be practical means for safe and long-term economic field development. The selected papers highlight areas of current research focused on developing solutions and proper planning of safe hydrocarbon exploitation. Other interesting papers involving field applications and case studies, in no way less important, have been identified for additional reading. Recommended additional reading at OnePetro: www.onepetro.org. SPE 146650 Mechanical Modeling of Shape-Memory Polyurethane Foam for Application as a Sand-Management Solution by Cem Ozan, Baker Hughes, et al. SPE 147044 The Use of Slotted Expandable Liners in Multizone Openhole Frac Packs: A New Completion Concept by David Mason, BP, et al. SPE 146721 Ceramic Screens, an Innovative Milestone in Sand Control by S. Mussig, Maersk Oil, et al.

Intelligent-Well-Monitoring Systems: Review and Comparison

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150195, ’Review, Analysis, and Comparison of Intelligent-Well- Monitoring Systems,’ by M.F. Silva Junior, Petrobras, and K.M. Muradov, SPE, and D.R. Davies, SPE, Heriot-Watt University, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed. Despite the maturity of intelligent-well (IW) equipment, the concept of an integrated IW as a key element in the “digital oil field” is still not developed fully. Current practice is to evaluate the IW value chain in a fit-for-purpose manner rather than by an integrated-modeling workflow. An increasing variety of real-time downhole monitoring and measurement systems is available for deployment or is in development. A well-founded understanding of data that are actually needed, the most suitable sensor types and interfaces, and availability of data-reconciliation and -validation methodology are key factors for the success of an integrated IW project. Introduction A subsea integrated production frame-work treats the reservoir, wells, flowlines, risers, and topside facilities as a single system. IWs can provide reservoir control by use of continuous monitoring and valve actuation in real-time. Integrated modeling and optimization, in this context, aims to capture the physics of the complex interactions across the processes for true operations support. Actual data are fed into the optimizer after data analysis and assimilation for model calibration and uncertainty minimization. The complete paper details how established concepts from control engineering and metrology can be used for reservoir management. Research and development efforts in permanent well monitoring are divided into two classes: deep-reservoir and near-wellbore. Additional value can be derived from these technologies because they also can identify and classify failures in downhole equipment. Deep-reservoir sensing is related to 4D seismic, dynamic 3D resistivity, and streaming potential (electrokinetic) monitoring techniques that capture the dynamics of the entire reservoir. Near-wellbore sensing includes classical downhole measurements, such as pressure and temperature. Also, monitoring systems have become a distributed sensing network instead of an autonomous system, which requires an understanding of all errors and limitations in the signal path aside from the sensor itself. IW-Monitoring Systems The physical quantities measured by equipment from different manufacturers of sensors for downhole, near- wellbore permanent monitoring of an IW are very similar: pressure, temperature, flow, acceleration (seismic and acoustic), and strain. The differences between them and their limitations are related mostly to the equipment and its installation requirements. The measurement of new physical quantities for deep-reservoir monitoring, such as seismic, electromagnetics, and streaming potential, is in the early stages of development.

Feasibility of monitoring hydraulic fracturing using time-lapse audio-magnetotellurics

Hydraulic fracturing is widely used for initiating and subsequently propagating fractures in reservoir strata by means of a pressurized fluid to release oil and gas or to store industry waste. Downhole or surface microseismic monitoring is commonly used to characterize the hydraulically induced fractures. However, in some cases, downhole microseismic monitoring can be difficult due to the limitation imposed by boreholes. Surface microseismic monitoring often faces difficulties acquiring high signal-to-noise ratio data because of the on-site noise from hydraulic fracturing process. Research and field observations indicate that injecting conductive slurry or water into a strata may generate distinct time-lapse electromagnetic anomalies between pre- and posthydraulic fracturing. These anomalies provide a means for characterizing the hydraulic fracturing using time-lapse electromagnetic methods. We examined the time-lapse variation over an hour, one day, one month, and two years of observed audio-magnetotellurics (AMT) resistivity and the 1D and 3D AMT modeling result of the variation pre- and posthydraulic fracturing. There is also a successful case history of applying the time-lapse AMT to map hydraulic fractures. Observed data indicate that the variation of AMT resistivity is normally less than 6% apart from the data of the dead band and some noisy data. Modeling results show the variation pre- and posthydraulic fracturing is larger than 30% at the frequency point lower than 100 Hz. The case history indicates that time-lapse magnetotelluric monitoring may form a new way to characterize the hydraulic fracture.

Fiber Bragg Grating-Based Quasi-Distributed Temperature Sensor for Down-Hole Monitoring

Fiber Bragg Grating-Based Quasi-Distributed Temperature Sensor for Down-Hole Monitoring

Transferring Intelligent-Well-System Triple-Gauge Data Into Real-Time Flow Allocation

Summary Knowing the exact flow allocation for each controlled zone is important for well optimization and the management of an intelligent well system (IWS). For two-zone IWS producers, a broadly accepted downhole gauge configuration uses the triple-gauge system, where two gauges give the upstream-side pressure/temperature (P/T) of the two downhole control valves and one gauge gives the P/T inside tubing of the commingled fluid [Baker Hughes IWS installation (2012) and Halliburton-WellDynamics IWS installation (2012) databases]. Theoretically, this configuration gives the P/T boundary conditions between the two valves and the gauge carrier, where flow allocations can be solved numerically, on the basis of the gauge readings and control-valve settings. However, from what we have seen in the past 10 years of IWS applications, only a few have published successful application cases regarding this topic. Is this an indication that a large number of two-zone triple-gauge IWS wells are operating in the low-confidence region of the two zone's production flow allocations? In this work, a comprehensive hydraulic model has been developed to address this topic. This paper will discuss a recent application of such a model to estimate the flow allocations of an existing two-zone deepwater IWS oil producer. The well began production in 2007. A total of 1,362 daily triple-gauge data points are available for this study, where the monitored P/T data indicate that the well was flowed in multiphase conditions at downhole for a large percentage of its production life. Verification was completed by comparing the predicted flow-allocation results with this well's measured total rates and daily-allocation rates. Further comparisons of the zonal allocations, between the model calculated results vs. the zonal-reservoir deliverability-study predicted results, were also provided. These comparisons showed a good match between the predicted results, measured data, and the available reservoir-study results. Descriptions of key factors to address the accuracy of the method have been provided, including compensated differential pressure, multiphase choke model, choke-discharge coefficient, and fluid pressure/volume/temperature (PVT) behavior impact. Sun's modified multiphase choke model was proposed in this study. The authors believe it will be more suitable for downhole valve operating and multiphase-flow conditions. This case study has proven a very promising independent solution for continuous well-rate estimation, with the solution based purely on choke-pressure drops and intelligent well-valve positions. The downhole monitoring P/T is normally based on seconds, which means that intelligent well-flow allocations can be calculated in real time without installing downhole venturi flowmeters that may add completion cost. In addition, a venturi flowmeter provides a smaller ID profile for the completion strings above/below it, which is inconvenient for future potential wellbore interventions. This solution brings measurable benefits for those IWS wells with no downhole flowmeters when taking into account the time and effort spent on periodic production tests, reservoir/well deliverability studies for production allocations, and potential production loss during the production tests.

Wireless Wellbore - The Way Ahead

Technology Update The trend of increasing wellbore complexity for extended reservoir contact and greater reservoir heterogeneity demands improved monitoring and control solutions. Traditionally, the only option has been the deployment of a cabled system, but this limits the application of intelligent well technology to new installations or workovers. In any case, cabled systems are not always possible in new installations, especially where the completion is discontinuous, and slimhole or monobore completions may not allow cables to be deployed along the tubing string. Wireless technology is proving to be a more flexible alternative to addressing the issues of permanent downhole monitoring. Tendeka’s wireless gauge, an interventionless completion technology that has been successfully deployed in the North Sea, allows real-time flowing bottomhole pressure (FBHP) to be efficiently transmitted to the surface, an attractive option for wells, in which the cabled gauge system has failed or was not initially installed. Originally designed to 3.5 in., the company has recently produced a 2.25 in. version. Benefits of Wireless Technology The system transmits data from the lower completion to the surface via pressure pulses. The tool design allows the well’s production to be partially choked for a short time to create a pressure pulse, which is detectable on the surface pressure gauge. The well’s energy is used to transmit data to surface, thereby reducing power consumption, and the system requires no additional surface installation or pickup because an existing tubing head pressure gauge can be used to detect the pulse train. For most operators, the system can be deployed by a single intervention, allowing highly accurate data to be sourced almost instantaneously for a fraction of the cost of a recompletion. Compared with a memory gauge system, it allows data to be collected in real time and provides a continuous confirmation of operation. The gauge can be set in blank pipe, giving optimal freedom for installation depth, and it can be installed as close to the producing interval as required. A benefit of using pressure pulse transmission is the ease of installation. No retrofitting of topside equipment is required, and many of the technical and contractual issues are avoided when introducing a new monitoring system. Successful Deployment A major operator in the North Sea retrofitted the 3.5 in. wireless pressure and temperature gauge at 2200 m in a low-pressure (32 bar) gas well offshore Norway. The existing wellhead pressure sensor was used to capture the wireless signal and extract the data, therefore, no extra infrastructure was required. The application was especially challenging because the well was a marginal producer and the wellhead pressure had large background pressure variations, because of limited well deliverability. Despite these conditions, pressure pulse transmission proved effective. Even if the well starts to significantly deplete while the wireless downhole gauge is installed, the gauge itself will modify its pressure pulsing method to ensure that a detectable pulse train is transmitted to surface.

Closed-loop Feedback Control for Production Optimization of Intelligent Wells under Uncertainty

A key component of intelligent-well systems is the decision framework used to identify control actions for production optimization. Most published algorithms use model-based control, yet model-based techniques are effective only if the model or ensemble of models used in the optimization captures all possible reservoir behaviors at the individual-well and -completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We show that simple, closed-loop feedback control, triggered by monitoring at the surface or downhole, can increase the net present value (NPV) and mitigate reservoir uncertainty. We do not neglect reservoir-model predictions entirely; rather, we use a model-based approach to optimize adjustable parameters in feedback-control strategies. We compare open-loop control, by use of fixed control devices (FCDs), with closed-loop feedback control, by use of “on/off” inflow-control valves (ICVs), operated in response to monitoring at the wellhead, and “variable” ICVs operated in response to monitoring downhole. We also use a gradient-based optimization algorithm to find the dynamic optimal inflow-control behavior. This strategy assumes perfect reservoir knowledge and is implemented only for benchmarking of the feedback-control strategies. Our result suggests that closed-loop control, on the basis of direct feedback between reservoir monitoring and inflow-valve settings, can yield close-to-optimal gains in NPV compared with uncontrolled production, even if the reservoir behavior lies outside the range predicted by reservoir models. Moreover, similar gains are observed by use of surface monitoring and simple on/off ICVs, and downhole monitoring and variable ICVs. In contrast, open-loop control yields significantly lower NPV gains, and is also a riskier strategy because unpredicted reservoir behavior can yield suboptimal sizing of the FCDs and negative returns.

Design of the Oil Well Multi-Parameter Monitoring System

As the information collection device of the current domestic down-hole gathers less information and with low precision, the down-hole monitoring system with multi-parameter is designed in this paper. The system can be used on electric submersible pump to achieve two-way pressure, two-way temperature, leakage current, and vibration signals in real-time acquisition. Filtering the collected data, and using curve fitting algorithm on the pressure sensor for temperature compensation to ensure the accuracy of the data. Test results show that the system can withstand the harsh down-hole environments encountered in an oil well. Plus, the gathered data has high precision and timeliness. Accordingly, it reaches the expected target.

Full-waveform based complete moment tensor inversion and source parameter estimation from downhole microseismic data for hydrofracture monitoring

Downhole microseismic monitoring is a valuable tool in understanding the efficacy of hydraulic fracturing. Inverting for the moment tensor has gained increasing popularity in recent years as a way to understand the fracturing process. Previous studies utilize only part of the information in the waveforms, such as direct P- and S-wave amplitudes, and make far-field assumptions to determine the source mechanisms. The method is hindered in downhole monitoring, when only limited azimuthal coverage is available. In this study, we develop an approach to invert for complete moment tensor using full-waveform data recorded at a vertical borehole. We use the discrete wavenumber integration method to calculate full wavefields in the layered medium. By using synthetic data, we find that, at the near-field range, a stable, complete moment tensor can be retrieved by matching the waveforms without additional constraints. At the far-field range, we discover that the off-plane moment tensor component is poorly constrained by waveforms recorded at one well. Therefore, additional constraints must be introduced to retrieve the complete moment tensor. We study the inversion with three different types of constraints. For each constraint, we investigate the influence of velocity model errors, event mislocations, and data noise on the extracted source parameters by a Monte Carlo study. We test our method using a single well microseismic data set obtained during the hydraulic fracturing of the Bonner sands in East Texas. By imposing constraints on the fracture strike and dip range, we are able to retrieve the complete moment tensor for events in the far-field. Field results suggest that most events have a dominant double-couple component. The results also indicate the existence of a volumetric component in the moment tensor. The derived fracture plane orientation generally agrees with that derived from the multiple event location.

Research on Communication Method for the Coal Mine Drainage Control System

The communication method of the automatically drainage monitoring system for underground coal mine is researched. The advanced PLC control technology and visual InTouch human-machine interface are used to design the control system. The information which is measured by downhole monitoring device can be real-timely transmitted to the ground monitoring stations through the Ethernet optical fiber communication system.The monitoring system can realize on-site manual and automatic control, also can realize remote monitoring and management.This paper mainly describes the implementation process and implementation principle of the data transfer between control unit and remote host computer via Ethernet technology.

Effective VTI anisotropy for consistent monitoring of microseismic events

The monitoring of induced or triggered microseismic events increasingly is being used to inform the efficient production of unconventional reservoirs. A key aspect of economic production in these low-permeability rocks is hydraulic fracture stimulation, usually in horizontal wells. To evaluate the success of the stimulation, engineers rely on monitoring the induced (or triggered) microseismic events that are then interpreted to map the stimulated reservoir volume and likely drainage area of the well. These microseismic events can be mapped either from downhole or surface monitoring arrays. In this study, we discuss a newly developed methodology that allows economic and consistent mapping of microseismic events from multiple stimulated wells across an entire field. This approach allows better comparison of stimulation techniques between wells in order to optimize long-term development of the reservoir. As well, the method enables a relatively robust observation of velocity anisotropy that leads to better wave-propagation modeling and more accurate event locations

Crossing the Technology Chasm: Permanent Downhole Monitoring

Editor’s note: This is the third and final installment of a multipart series examining key upstream technology uptake challenges in the oil and gas industry, and the reasons for the lack of accelerated acceptance of viable technologies needed to exploit increasingly challenging drilling and production environments. Similar to the managed pressure drilling (MPD) article published in the February JPT and the seismic while drilling (SWD) article in March, a permanent downhole monitoring (PDM) survey was conducted among SPE readership around the world. In total, about 1,500 SPE members responded to the survey. The majority of the respondents were operators (64%) and technology providers (13%). Unlike the previous two technologies analyzed, PDM generally has a higher level of acceptance among operators because it has been on the market for a longer time, and because significant reliability and performance improvements have occurred over the past several years. A key question in the survey was: “What are the main value propositions you see for permanent downhole monitoring?” As shown in Fig. 1, the most important value propositions were: 1) optimizing production through continuous information, 2) avoiding the necessity to shut in the well to obtain pressure ratings, and 3) emerging distributed temperature capabilities that add further value in understanding and optimizing production. There was general agreement among both operators and technology providers on the importance of these benefits. The relevance of these value propositions was stated by Shahab Mohaghegh, president of Intelligent Solutions: “The thought of being able to know what is going on in the well and in the reservoir in real time is very exciting. You imagine sitting in your office thousands of miles away from the field and being able to decide what needs to be done and then being able to see the consequences of your decision in near real time.” A similar view was expressed by Garrett Skaggs, monitoring product champion at Schlumberger. “The value of permanent downhole monitoring systems stems from the ability to provide continuous, reliable well and reservoir performance information without the need for intervention,” he said. “These measurements enable operators to manage decisions regarding hydrocarbon assets including production optimization, problem identification and diagnosis, updating reservoir models, and field development planning.” The growing importance of fiber optic technology and distributed temperature sensing was also raised by a number of operators. Significant improvements in these systems over the past few years have led to an increased acceptance of this downhole technology. In the view of Glynn McColpin, director of reservoir monitoring at Pinnacle (a Halliburton service): “I think we are actually seeing the next wave with fiber optic sensing. Electronics can only get you to a certain temperature, then you start worrying about longevity and failures. You start looking at the fiber optic solutions coming out—we can go into steam wells up to 350°C with just glass and the glass itself is a sensor.”

Comments: Highlighting New Technology

Editor's column Last year, the SPE Board of Directors created a task force headed by its technical directors to examine how the society could help accelerate the acceptance and awareness of new upstream technology. The issue is of particular importance now as the industry strives to increase recovery factors and tap new hydrocarbons to meeting escalating global demand. The task force noted that one of SPE’s goals is to provide the means of transferring technology through the technology life cycle—from inception to maturity—including early in the cycle of “emerging technology.” SPE has been strong in transferring more mature technology through its many publications, conferences, lectures, and workshops. But highlighting “young” technology presents a challenge. Technology that is new in the development cycle often does not lend itself to technical papers, the lifeblood of many SPE events and publications. To that end, the SPE Technical Directors’ Technology Pipeline Task Force aims to accelerate emerging technology through publications and other vehicles. JPT is a natural ally in that goal. JPT is now soliciting information on new and emerging technologies to publish and inform the upstream oil and gas community of their potential. Companies and individuals are invited to submit information on their new technologies for possible publication, both in the JPT print edition and online, by submitting a template that describes the technology and what it can do. The template outlines the minimum content necessary for inclusion. Developers of technology will need to define the reason or need for the technology, its purpose, describe how it works, state its target applications, and note how and where it has been used. In addition, the submission must provide information on any case studies, discuss what would cause the new technology to not work or fail, and describe the possible health, safety, and environmental impact. The technology must provide significant benefits beyond commonly used technologies. It must also be original and, to a certain degree, groundbreaking. Future plans for the technology and whether it has been commercially developed should be given, and a company website and contact information provided. The information should avoid undue commercialism, product cost information, and the use of trademark or other commercial symbols. The technology must be no more than two years old, meaning less than two years since its full commercial deployment or introduction to the marketplace. Companies are not limited to one submission. The sub-missions will be reviewed by SPE’s technical directors for possible inclusion in JPT. In addition to this effort, JPT staff are making a special effort to cover emerging technology and its potential for acceptance in the industry. This month’s issue concludes a three-part series on promising technologies that are vying for wider industry acceptance—managed pressure drilling, seismic while drilling, and permanent downhole monitoring—and other recent articles have covered digital rocks and other promising technologies. If you are interested in submitting information on your new technology or have any questions about this process, please contact me at jdonnelly@spe.org.

Laboratory Measurements and Numerical Modeling of Streaming Potential for Downhole Monitoring in Intelligent Wells

Summary Downhole monitoring of streaming potential, using electrodes mounted on the outside of insulated casing, is a promising new technology for monitoring water encroachment toward an intelligent well. However, there are still significant uncertainties associated with the interpretation of the measurements, particularly concerning the streaming potential coupling coefficient. This is a key petrophysical property that dictates the magnitude of the streaming potential for a given fluid potential. We present the first measured values of streaming potential coupling coefficient in sandstones saturated with natural and artificial brines relevant to oilfield conditions at higher-than-seawater salinity. We find that the coupling coefficient in quartz-rich sandstones is independent of sample type and brine composition as long as surface electrical conductivity is small. The coupling coefficient is small in magnitude, but still measurable, even when the brine salinity approaches the saturated concentration limit. Consistent results are obtained from two independent experimental setups, using specially designed electrodes and paired pumping experiments to eliminate spurious electrical potentials. We apply the new experimental data in a numerical model to predict the streaming potential signal that would be measured at a well during production. The results suggest that measured signals should be resolvable above background noise in most hydrocarbon reservoirs. Furthermore, water encroaching on a well could be monitored while it is several tens to hundreds of meters away. This contrasts with most other downhole monitoring techniques, which sample only the region immediately adjacent to the wellbore. Our results raise the novel prospect of an oil field in which the wells can detect the approach of water and can respond appropriately.