The artificial lift system (AL) is the most efficient production technique in optimizing production from unconventional horizontal oil and gas wells. Nonetheless, due to declining reservoir pressure during the production life of a well, artificial lifting of oil and gas remains a critical issue. Notwithstanding the attempt by several studies in the past few decades to understand and develop cutting-edge technologies to optimize the application of artificial lift in tight formations, there remains differing assessments of the best approach, AL type, optimum time and conditions to install artificial lift during the life of a well. This report presents a comprehensive review of artificial lift systems application with specific focus on tight oil and gas formations across the world. The review focuses on thirty-three (33) successful and unsuccessful fieldtests in unconventional horizontal wells over the past few decades. The purpose is to apprise the industry and academic researchers on the various AL optimization approaches that have been used and suggest AL optimization areas where new technologies can be developed.
Nguyen, Dzu (BP) | Macleod, Innis (BP) | Taylor, Donald (BP) | Murray, Laurence (BP) | Zavyalov, Denis (BP) | Booth, Dave (Fircroft Consultant, former BP) | Robertson, Neil (Halliburton) | Smith, Robert (Halliburton) | Joubran, Jonathon (Halliburton) | Allen, Clifford (Halliburton) | Shafei, Sharil Mohd (Halliburton)
The multiple zone water injection project (MZWIP) was initiated to deliver the following key objectives: deliver zonal injection with conformance control and reliable sand management across the major layered sands of the Balakhany unconsolidated reservoirs in the BP operated Azeri-Chirag-Gunashli (ACG) fields in Azerbaijan sector of the Caspian Sea.
Three years after MZWIP implementation, six wells with a total of 14 zones are injecting at required rates with zonal rate live-reporting. To achieve this multizone injection facility, the requirement for a standard ACG sand-control injector design was discounted and a non-standard sand management control technique developed using a cased & perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world's first 10kpsi three-zone inline variable-choke DHFC wells with distributed temperature sensors (DTS) across all target injection zones.
The choking DHFC provides flexibility in operations and delivers the right rates to the right zones. The DTS provides conformance surveillance, fracture assessment, caprock integrity and sand ingress monitoring capability. A customized topside logic control system provides an automatic shutin of interval control valves (ICVs) during planned or unplanned shutins to stop crossflow and sand ingress and is the primary method of effectively managing sanded annuli.
The development of this MZWI solution has significantly changed the Balakhany development plan and has been quickly expanded across five ACG platforms. Accessing 2nd and 3rd zones in the same wellbore, this C&P DHFC well design is accelerating major oil volumes and will significantly reduce future development costs, maximizing wellbore utility in a slot-constrained platform.
Banack, Ben (Halliburton) | Burke, Lyle H. (Devon Canada Corporation) | Booy, Daniel (C-FER Technologies 1999 Inc.) | Chineme, Emeka (Cenovus Energy) | Lastiwka, Marty (Suncor Energy) | Gaviria, Fernando (Suncor Energy) | Ortiz, Julian D. (ConocoPhillips Canada) | Sanmiguel, Javier (Devon Canada Corporation) | Dewji, Ayshnoor (Halliburton)
It is becoming common to install inflow control devices (ICDs) along steam-assisted gravity drainage (SAGD) production liners to enhance temperature conformance and accelerate depletion. Additionally, some operators advocate the installation of similar outflow control devices (OCDs) along the injection well of the SAGD well pair. Collectively, these inflow and outflow devices are often referred to as FCDs. Industry adoption of flow control devices (FCDs) has increased, and several devices are commercially available for use in SAGD.
In an effort to optimize FCD design and selection, a joint industry partnership (JIP) was formed (
Fiber-optic-based instrumentation was deployed within FCD-equipped wells using permanently installed coiled tubing. Well architecture design changes to a typical completion were not required because fiber-optic sensors are used for most non-FCD wells to collect distributed temperature sensing (DTS) data. Although DTS is a common tool for optimizing SAGD production, it has certain limitations; specifically, temperature changes along production wells do not typically allow a detailed definition or quantification of the inflow distribution along the wellbore.
In addition to DTS, distributed acoustic sensing (DAS) was periodically performed on the FCD wells. DAS logging of SAGD producers has several potential uses, including flow profiling, steam breakthrough and/or noncondensable gas (NCG) detection, multiphase flow characterization, electric submersible pump (ESP) performance, completion failure analysis, and four-dimensional seismic analysis. Although FCD characterization with DAS appears promising, a knowledge gap exists as to how to move beyond qualitative analysis to more quantitative analysis of FCD performance and the lateral emulsion inflow distribution. Pending satisfactory results, DAS logging on active wells can potentially be completed to accelerate improvements of SAGD FCD performance and design as well as increase the efficiency of SAGD recovery through improved steam/oil ratio (SOR) and an associated reduction in greenhouse gases.
This paper describes piloting the collection and analysis of DTS and DAS data to help improve understanding of SAGD inflow distribution. Logs were performed on multiple wells during stable and transient flowing conditions. Early surveillance demonstrated suitability and limitations of fiber-optic-based logging to validate FCD performance in active wells. In addition to field logging, acoustic recording using JIP flow loop testing was completed with accelerometers, geophones, and fiber-optic cables during FCD characterization. The goal was to cross reference the acquired acoustic signals for quantification of flow at devices and validation of performance. An overview of the JIP flow loop FCD acoustic characterization program is described.
Lastiwka, Marty (Suncor Energy) | Burke, Lyle H. (Devon Canada Corporation) | Booy, Daniel (C-FER Technologies 1999 Inc.) | Chineme, Emeka C. (Cenovus Energy) | Gaviria, Fernando (Suncor Energy) | Ortiz, Julian D. (ConocoPhillips Canada)
A review of laboratory and field testing of a new flow control device is presented in this paper. The device is designed specifically to limit steam breakthrough in thermal operations.
For the past few years, four companies operating Steam Assisted Gravity Drainage (SAGD) facilities in Alberta's oil sands have come together to study downhole Flow Control Devices (FCDs) in a laboratory setting and to share field data of the application of such devices. Within this collaboration, a new device was designed to address the challenge specific to thermal operations, namely limiting steam breakthrough into production wells. Laboratory tests were undertaken to define the steam-limiting characteristics of this device under field representative SAGD conditions at full scale rates, temperatures and pressures. Tests were performed with oil to gauge viscosity sensitivity, as well as with water and steam at various inflow rates, temperatures and steam qualities. Testing was also performed with Non-Condensable Gas (NCG) to help assess how methane production may affect performance under both low and high Gas Volume Fraction (GVF) conditions. Finally, three-phase erosion testing was performed using water, quartz and air, allowing a realistic, scalable assessment of the device's long-term reliability.
Highlights from these tests are reported and compared to results from testing of conventional, commercially available devices. The new device has shown superior performance relative to other devices designed for non-thermal applications. Thus, it inhibits the influx of steam while allowing the flow of emulsion into a production well. Based on the results of laboratory testing, the device is currently being tested in field operations. Early indications are that the device is performing as expected. Preliminary field data are presented.
Laboratory testing of thermal flow control devices is especially challenging and unique when compared with similar testing for conventional flow control devices. This becomes more evident when testing devices designed specifically to limit steam breakthrough. Furthermore, in thermal operations, the phase change potential that is inherent when operating near the saturation point of water opens new possibilities in the design of flow control devices. A successful, practical implementation of this phase change characteristic was achieved in a collaborative environment.
Ugueto, Gustavo A. (Shell Exploration and Production) | Todea, Felix (Shell Canada Limited) | Daredia, Talib (Shell Canada Limited) | Wojtaszek, Magdalena (Shell Global Solutions International) | Huckabee, Paul T. (Shell Exploration and Production) | Reynolds, Alan (Shell Exploration and Production) | Laing, Carson (OptaSense) | Chavarria, J. Andres (OptaSense)
The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation. Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions. To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings. The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
Ghazali, Ahmad Riza (PETRONAS) | Abdul Rahim, M. Faizal (PETRONAS) | Mad Zahir, M. Hafizal (PETRONAS) | Muhammad, M. Daniel Davis (PETRONAS) | Mohammad, M. Afzan (PETRONAS) | A. Aziz, Khairul Mustaqim (PETRONAS)
The key objectives were to achieve better seismic resolution and spatial delineation in very heterogeneous reservoirs. We decided to supplement simultaneously the surface 3D multi component seismic acquisition by placing additional fiber optic live receivers in the subsurface via a "True-3D" experiment without shutting down the oil production. The most cost-effective method to snapshot this wavefield propagation downhole is by utilizing fiber optic Distributed Acoustic Sensing (DAS). The borehole 3D VSP data were acquired by sharing the surface OBN nodal survey airgun sources. This is an important experiment for the field in the future so that the need to halt insitu field production for 4D time lapse monitoring will not be required if the S/N is acceptable by using this method. This permanent installation of fiber optic cables has become our ears on wells, not only for 3D DAS VSP but for proactive monitoring of the field, ensuring optimum production performance throughout the life of the field.
DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO2 and Naptha in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications.
A full-physics simulator is used to model the process. The technical as well as economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics.
The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. The objective function built with economic parameters helped to maximize the NPV for the project, providing a more realistic perspective on the projects. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO2 and naptha indicate that the two have different dominant modes of improving recovery of steam only injection. CO2 increases the extent of the steam chamber while lowering the steam temperature significantly.
This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.
An optical fiber has been utilized to continuously acquire liquid production profiles in horizontal well in X oilfield. The results obtained from the dynamical monitoring system confirm the time-varying law of the physical property under the condition of high-water flooding, which can serve as the guidelines to explore the potential of remaining oil in high water-cut/high recovery factor oilfield.
Usually, the sound wave shows different propagation speeds in different medium, which is the basic principle of this test. Firstly, optical cable is used for sound wave detection and signal demodulation.Meanwhile, a series of other processes are applied to calculate the sound velocity of mixed medium; Then the volume velocity and holdup of mixed medium for each phase are determined.The measure of liquid-producing profile along the whole horizontal well has been realized in real time. Finally, numerical simulation model considering the time-varying physical properties is established based on the core flooding laboratory experiment. This result will provide guidelines for the exploration of remaining oil in the well.
The results obtained from optical fiber monitoring system during last two years show that 80% of the fluid produced from the 502-meter horizontal well is mainly contributed to the first 90-meter horizontal section. Experimental results of core flooding under excessive water flooding (2000 pore volume) indicate that the permeability is 1.4 times of the original. The results of numerical simulations considering the time-varying physical properties illustrate that there is still internal remaining oil along the horizontal well section. So, the strategy of exploiting potential oil is proposed using an accurate directional water plugging, which will decrease 10% water cut and obtain more recoverable reserves.
Based on the dynamical monitoring results of optical fiber, this paper innovatively provides the strategy of exploiting potential remaining oil in the horizontal wells, which can provide a valuable suggestion for offshore oilfield with high productivity at high water-cut stage.