Openhole Packer Research Articles

Technology Focus: Acidizing (June 2023)

The first acid job dates to 1895. Challenges remain, however, when it comes to lithology, coverage, penetration, and management of reaction products. These themes remain a focus for stimulation engineers. In paper SPE 204879, for example, a novel in-situ foam-generation system is introduced that provides effective diversion and leaves no residue. Field applications suggest significantly better performance compared with other diversion systems. In paper SPE 203985, the authors present a 3D acid-fracturing model to calculate fracture geometry induced through multistage alternating injection of pad and acid fluids. Alternating acid with high-viscosity polymer pad promotes nonuniform acid etching and viscous fingering, which leads to longer and narrower channels. Concurrently, investigators are studying methods to achieve effective near-wellbore and far-field bridging using a combination of solids and fiber-laden acid. For those wishing to delve deeper into this subject, paper SPE 206255 makes interesting reading. Completions can play a role in improving acid treatments. Limited entry, as presented in paper SPE 211394, and the so-called “segmented and selective” completions are at the forefront. Paper IPTC 23003 introduces the concept of sweet spots, which are then completed selectively with packers and sliding sleeves. Paper SPE 213406 describes a relatively complex architecture for a trilateral TAML Level 2 well with openhole packers and ball-activated sleeves. Thus, it can be said that most enabling technology is out there. Lastly, engineers have begun to leverage benefits that big data and artificial intelligence potentially offer. Predicting an outcome of an acid job remains hit-and-miss at best—a gap engineers must bridge. In paper SPE 208172, the authors present a predictive model to estimate the efficiency of acid-fracturing treatments in naturally fractured reservoirs using an artificial neural network. They report a predictability error of less than 10%. This may be what we are looking for. I hope you find the selections enlightening. Recommended additional reading at OnePetro: www.onepetro.org. SPE 207514 Subsea Multiwell High-Flow-Rate Riserless Acid Stimulation Campaign With Two-Vessel Approach: A Comparative Case Study by Irma Kusumawati, ConocoPhillips, et al. SPE 205599 A New Method of Carbonate Matrix Stimulation Modeling and Optimization Using Field Experimental Data for Acid Efficiency Calibration and Case Studies in Kazakhstan by Ruslan Kalabayev, SLB, et al. SPE 209673 Reducing Carbon Footprint of Matrix Acidizing in Carbonate Formations: How Much Acid Do We Really Need To Pump? by Mahmoud T. Ali, Baker Hughes

Case Study of Successfully Staged Acid Fracturing on the Ultra-Deep Horizontal Well for the Qixia Fm HTHP Tight Carbonate Gas Reservoir in China

The lower Permian Qixia formation gas reservoir is characterized by ultra-deep buried, high temperature and high pressure (HTHP), low porosity and permeability, ultra-high closure pressure, and thin thickness in the western Sichuan Basin, China. Acid fracturing has been adopted as the main well stimulation technology. The average test production of the acid-fractured vertical well was 46 × 104 m3/d. The horizontal well with staged acid fracturing is considered a reliable measure to enhance gas production. However, the staged acid fracturing on the ultra-deep horizontal well has been challenged. The reaction rates of conventional, self-diverting, and gelled acid and the acid-etched fracture conductivity experiments under HTHP are measured to optimize the acid fracturing technique. The reaction rate of gelled acid with Qixia Fm limy dolomite at 150°C is 3.4–6.7 times faster than that with dolomite and similar to that with limestone. The gelled acid with better retardation and friction reduction performance is selected as the main acid to increase the effective acid-etched fracture length. The acid-etched fracture conductivity can be greatly enhanced by using gelled acid, increasing acid volume, and closed fracture acidizing (CFA) under a closure stress of 50 MPa. Moreover, the feasibility of staged acid fracturing for ultra-deep horizontal wells is discussed. The first stage is assembled by fracturing sleeve, spared ball drop sleeve, and circulating valve to ensure activation of the fracturing channel. The tested production is significantly enhanced with temporary plugging and open-hole packer and sliding sleeve staged acid fracturing.

Technology Focus: Completions (April 2022)

Data science continues to provide solutions for unconventional-well challenges. But innovative combinations of proven technologies also are delivering improved success in artificial lift wells. The articles I have selected for this feature provide details on these achievements. But can the learnings from one type of completion improve success in other types of completions? The shale gas revolution is over 20 years old. The pace of innovation has been rapid, and many technologies and methods have been developed that reduce completion time and maximize access to the reservoir with one well. Unconventional-well innovation, therefore, has led to constant improvements in efficiency and reliability. There is no doubt this will continue, but can unconventional learnings be applied in conventional completions? Electrical submersible pumps (ESPs) and intelligent-completion technologies are complementary, but each have very different service lives. For example, intelligent-completion hardware may have a 20-year service life, while ESPs may have a 2-year service life. So how can they be integrated in a way that ensures long-term reliability in the intelligent completion while accommodating periodic ESP workovers? Reimagining completion architecture is one way that a Middle East operator has achieved this goal. Can large logging-while-drilling and measuring-while-drilling data sets be used to optimize completion of the well? One paper explains how perforation cluster design in Marcellus wells can be optimized by analyzing these data sets using a convolutional neural network model. The key to optimization involves mechanical specific energy. Is the lesson here to drill with the completion in mind or to complete with drilling in mind? Will drilling engineers and completion engineers answer the last question differently, or will they agree on a different paradigm for the next well or project? It has been said that you will get the same result by repeating what you have done. But if you want to have a better result, you must change what you are doing. Is it time for a paradigm shift? Recommended additional reading at OnePetro: www.onepetro.org. SPE 199712 - Evaluating Limited-Entry Perforating and Diverter-Completion Techniques With Ultrasonic Perforation Imaging and Fiber Optic DTS Warmbacks by Chase Murphree, SM Energy, et al. SPE 207862 - Modeling a Novel Approach To Delay the Water Breakthrough in Gas Cap Wells Using Smart Completions: Case Study Onshore Abu Dhabi Field by Aditya Ojha, ADNOC, et al. SPE 201268 - DTS Flow Profiling for a Horizontal Multistage Fractured Well in Tight Gas Reservoirs by Improved Model Considering an Openhole Packer Completion Scenario by Weibo Sui, China University of Petroleum, et al.

Bayesian prior distribution based on generic data and experts’ opinion: A case study in the O&G industry

Reliability estimation is an essential task to ensure predictability on the life of equipment installed in oil wells, allowing forecasting costs, planning maintenance, and estimating system availability. However, data may be rather scarce and/or expensive to obtain, especially for technologies under development in the Oil and Gas (O&G) industry. The information is frequently available in generic databases and expert opinions. In the Bayesian framework, the prior knowledge about a system's reliability is updated as a new field and/or test data are gathered. This paper proposes an approach that does not require direct elicitation of parameters to define informative prior distributions for the reliability function using fault tree analysis, expert's opinions, and/or generic data at the system level of equipment under development. Specifically, the method-of-moments and maximum-entropy are adopted to propagate downward the uncertainty from the system level through the failure modes until the basic events of the fault tree, weighted by the expert knowledge of the failure behavior. Then, in possession of all prior distributions of the basic events, the information may be propagated upward based on Monte Carlo simulation to update the system reliability distribution. Finally, we present a case study of the proposed methodology applied to a novel open-hole expandable packer, a completion equipment recently installed in a Brazilian oil field. The failure modes and failure causes are discussed, and, after expert elicitation, the definition of the informative prior distribution is achieved. Therefore, we estimate the reliability for a given time and assess if the novel equipment attains the company's risk target, taking O&G standards as reference.

Performance Evaluation of Multistage Fractured Horizontal Wells in Tight Gas Reservoirs at Block M, Ordos Basin

Block M of the Ordos Basin is a typical low-permeability tight sandstone gas accumulation. To develop these reservoirs, various horizontal well fracturing technologies, such as hydra-jet fracturing, open-hole packer multistage fracturing, and perf-and-plug multistage fracturing, have been implemented in practice, showing greatly varying performance. In this paper, six fracturing technologies adopted in Block M are reviewed in terms of principle, applicability, advantages, and disadvantages, and their field application effects are compared from the technical and economic perspectives. Furthermore, the main factors affecting the productivity of fractured horizontal wells are determined using the entropy method, the causes for the difference in application effects of the fracturing technologies are analyzed, and a comprehensive productivity impact index (CPII) in good correlation with the single-well production of fractured horizontal wells is constructed. This article provides a simple and applicable method for predicting the performance of multi-frac horizontal wells that takes multiple factors into account. The results can be used to select completion methods and optimize fracturing parameters in similar reservoirs.

Improved DTS profiling model for horizontal gas wells completed with the open-hole multi-stage fracturing system

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and several reservoir/wellbore coupled thermal models were developed. Although these theoretical models are applicable only to some specific scenarios, the industry has realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model.In this paper, we extended the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, by considering the special feature of the openhole packer completion scenario. Since the formation fluid flows first through the fracture into the open-hole annular space between the formation and the production liner, and then flow along the annular space until meeting the frac port on the production pipe, a simulation sub-region was added for representing the open-hole annular space, which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-segment flow regime caused by the simultaneous flow and heat transfer in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to the Joule-Thompson cooling effects at the fractures and frac ports if their locations are not consistent.With the improved model, the synthetic cases were firstly used for studying the temperature characteristics and the effects of gas production rate and frac port location. Then the DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in the Erdos Basin of China was simulated and analyzed. The open-hole packer completion was taken into account in the simulation and the gas rate prediction is satisfactory.

Sand Screen with Check-Valve Inflow Control Devices

Summary Sand control screens are installed with an internal string (wash pipe) as required which, among other functions, provides a circulation path. In long horizontal wells, running a wash pipe consumes considerable rig time and may limit the ability to reach target depth. In cases in which fluid losses are experienced after screen installation, isolating the open hole with a fluid-loss control valve can be prolonged. This paper describes a wash-pipe-free solution for screen installation using a check-valve inflow control device (CV-ICD). ICD screens are commonly used to delay/restrict the influx of unwanted fluids such as gas or water. The wash-pipe-free solution integrates a check valve with the ICD to prevent outflow through the screen during circulation and allows inflow through the screen when placed on production. This solution uses a check ball that seals against the ICD during circulation but falls back on a porous retainer plate during production. The check ball and retainer plate can be dissolved by spotting a reactive fluid inside the screen or made to erode over time with production. Laboratory testing yielded the following results: the ICD with the check ball was shown to seal up to 5,000 psi; the check ball and retainer plate can be dissolved by a reactive fluid, which can be tailored to bottomhole temperature and the required time of dissolution; and the pressure activation test demonstrated that the maximum differential pressure to seat the ball was less than 5 psi. This CV-ICD solution has been applied worldwide in more than 35 wells, most of which were targeted to avoid running a wash pipe. However, in two wells the technology was successfully used to set openhole packers with a 5,000-psi setting pressure. In this paper, we present the wash-pipe-free ICD screen installation with a dissolvable check valve and the capability of setting a hydraulic packer without a wash pipe or intervention in the open hole. The novel contribution presented herein is the ability to integrate a ball and cage to existing nozzle-based ICDs by using dissolvable material to achieve the preceding results in this application.

Research and application of fracturing process for low permeability reservoir of Triassic in Junggar Basin

Baikouquan formation of Triassic in the northwest margin of Junggar Basin has long been regarded as the synonym of “alluvial fan, ultra-low permeability and no benefit”. Moreover, the effect of Triassic conglomerate reservoir reconstruction in Mabei oilfield is not obvious, which leads to ineffective production and benefit development. In this paper, based on the research results and practical production application of Triassic conglomerate reservoir fracturing reconstruction technology in Junggar Basin in recent years, four kinds of adaptive reservoir reconstruction technology for low permeability conglomerate reservoir are explored, which effectively improves the single well production and realizes the increase of reserves and productivity in conglomerate reservoir exploration. (a) In view of the three reservoir conditions of multiple sets of sand layers, large vertical oil and gas display span and large difference of stress between each set of sand layer and surrounding rock, in order to ensure that multiple sets of sand layers are effectively reconstructed, the separate layer fracturing technology is implemented. Before fracturing, the process can realize circulation fluid replacement, and after fracturing, it can realize combined production; (b) For the reservoir with poor physical properties and high formation pressure, which cannot realize the stratified fracturing of tubing packer, the casing bridge plug layered fracturing technology is adopted; (c) In view of the fact that the oil and gas reservoirs are mostly located in the upper part of the thick sand layer and the fractures extend downward to easily connect the water layer, the reservoir reconstruction technology of secondary sand addition is implemented; (d) In view of the poor physical properties of the reservoir, the oil and gas production after the vertical well fracturing is not high, or the initial oil and gas production is high, but the production decline is fast, unable to stabilize the production for a long time, the horizontal well multi-stage fracturing technology is implemented. The successful field application of the open hole packer ball sliding sleeve fracturing technology and the bridge plug perforation combined fracturing technology in horizontal wells is realized. The research and practical application of adaptive reservoir reconstruction technology further promote the reconstruction of Triassic low permeability conglomerate reservoir and single well production increase in Junggar Basin. It can be used for reference in other basins for low permeable conglomerate reservoir fracturing, and it presents good application value.

Review and Analysis of Zonal-Isolation Effectiveness in Carbonate Reservoirs Using Multistage Stimulation Systems

SummaryIt is common practice to complete long carbonate intervals with multistage stimulation treatments, especially in horizontal wells. Each zone is, typically, mechanically isolated using cement or openhole packers and then acid stimulated. It is important to pump the planned acid volume to the target zone without any significant loss into adjacent zones. Zonal–isolation effectiveness is rarely evaluated because of a lack of zone–specific pressure and/or temperature data. Instead, it is judged on the basis of job pressure response or post–job production logging. In this study, zone–specific pressure and temperature gauges allowed for a more effective review of zonal isolation during stimulation treatments.In this paper, we review zonal–isolation results from a series of high–rate acid jobs conducted in wells equipped with zone–specific pressure and temperature gauges. Twenty–one acid–stimulation jobs from thirteen different wells were reviewed to investigate the effectiveness of zonal isolation during and after treatment. The examples presented in this paper cover several different completion types: cemented and uncemented, intelligent well systems (IWSs), plug–and–perforate completions, and ball–activated sliding–sleeve completions. The analysis revealed several different pressures and/or flow communication patterns. Field examples and analysis results presented in this work will help engineers design and optimize the zonal–isolation distance in cemented and uncemented wells requiring multistage stimulation in carbonate fields without losing a significant pay length.

Application of Temporary Plugging Stimulated Reservoir Volume Fracturing in Mahu Conglomerate Tight Oil

On account of the influence of early technical level and transformation concept, the production of the test horizontal wells has been improved to a certain extent, but there are still some problems, such as low pressure decline, low sustainable and stable production capacity. Refracturing technology is one of the main measures to improve the output of old wells in domestic and foreign oilfields at the moment. However, the horizontal wells put into production in early stage of Mahu were segmented with open hole packer and ball sliding sleeve. Restricted by the current wellbore conditions, forced mechanical segmented refracturing could not be achieved. People make use of the high-strength temporary plugging system to automatically select geological dessert, realize multiple inter-layer and intra-layer steering, improve the complexity and sweep volume of artificial fractures, and achieve the partial function of stimulated reservoir volume fracturing, which has become the effective increase production technology and means.

Technology Focus: Completions (September 2015)

Technology Focus Like a fingerprint, every completion is unique and gives each well its own identity. The hardware selection, its deployment method, and the associated stimulation technique combine to create a one-of-kind completion, custom tailored for each application. It is this infinite variation that constantly fuels a collective desire to bring stability to the completion process. More so than ever before, the themes of efficiency and optimization serve as a backbone for completion design and execution. These themes remain valid under any market condition but become all the more significant in challenging or volatile climates. Well completions play a critical role in the overall productivity of a reservoir, which inherently drives the decision-making processes toward well efficiency and production optimization. While there are many gains to be had around more-efficient hardware and stimulation deployment, improving the overall well efficiency and optimizing the production profile through carefully designed and implemented completion strategies represent the true endgame. The challenge lies in accessing the key ingredient that enables harmonization of all the various components: data. Today, full-field studies comparing varying completion techniques with associated production performance are commonplace to evaluate and home in on optimum completion methods. Sensing technology, common to drilling and evaluation, continues to be integrated into completions, providing a front-row seat for the main event, production. The adage “knowledge is power” could not be more relevant in this context. Data collection and analysis, and subsequent controls, are what ultimately will enable the most-efficient and -optimized wells. The papers highlighted in this feature speak to these themes that have become ever-present within the completions community. This selection of case histories and new technology reinforces the inherent desire to achieve stability through efficiency and optimization, even under the most challenging of market conditions. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 170264 Electronic-Set Openhole Packer Installation in Campos Basin, Offshore Brazil: A Case History by G.D. Mendes, Baker Hughes, et al. SPE 170694 Acid-Soluble Plugs— Pressure-Tight Solution for a Preperforated Liner by E. Livingston, ConocoPhillips, et al. SPE/IADC 170547 Innovative Intelligent Multizone Gravel-Pack Completion Revives Production in Malaysian Brownfield by T.U. Ceccarelli, Schlumberger, et al. SPE 170738 Composite-Plug-Milling Efficiency Improvement Through Rheology Control—Lessons Learned From the Horizontal Completions in the Devernay Shale by Darren Huynh, Shell Canada, et al.

Acid-Soluble Plugs—Pressure-Tight Solution for a Preperforated Liner

Summary This paper covers the development, laboratory testing, and field testing of acid-soluble-plug (ASP) technology as a viable completion alternative to wireline- or tubing-conveyed perforating. The ASPs are installed in a preperforated reservoir liner and dissolve when soaked in acid, allowing access to the reservoir. This allows the technology to be easily applied in reservoirs in which matrix acid jobs or acid-fracturing techniques are used. The ASP technology was developed to reduce risk and cost associated with wireline- and tubing-conveyed perforating. ASPs were designed, manufactured, and field tested in both 5-in. and 7.625-in. reservoir liner sizes for wells in the Ekofisk field. The combination of laboratory testing and large-scale field testing influenced the design of the ASPs as well as the additives used in the acid systems used to dissolve them. From concept to initial field implementation, the process of ASP-engineering development took more than 2 years. The concept was in the beginning field-tested in deviated injectors, with ASPs installed in the deepest section of the reservoir liner. The field tests proved the ASP concept before depending on the technology in a horizontal producer with an uncemented, tubing-in-liner completion solution. The field tests showed that acid soaking dissolved the ASPs in the downhole environment and allowed efficient acid stimulation of the reservoir. It also reduced the number of wireline runs necessary to complete the well. When field tested in a tubing-in-liner completion application, installation of the ASPs in the reservoir liner eliminated tubing-conveyed-perforating runs. The reservoir liner was uncemented with mechanical openhole packers for zonal isolation. The ASPs provided a pressure-tight reservoir liner to set the packers against and eliminated fluid loss during the running of the inner completion string. Optimization of this technology is an ongoing process. The plug design itself continues to evolve as well as the operational steps to minimize the soaking time necessary to dissolve the plugs and to gain access to the reservoir.

A new semi-analytical model for predicting the performance of horizontal wells completed by inflow control devices in bottom-water reservoirs

Simulation and prediction the performance of horizontal wells completed by inflow control devices is the foundation of ICDs completion parameters design-optimization. In this work, a new semi-analytical model that couples the reservoir inflow to the downhole flow is developed for predicting the performance of horizontal wells with inflow control devices in a box-shaped reservoir with bottom-water drive. The reservoir inflow model is based on a 3D volumetric source model that incorporates reservoir permeability heterogeneity in the near well region, reservoir anisotropy, and near-wellbore formation damage. The downhole flow model considers pressure drops due to fluid flow in the tubing, ICDs, and annulus. The calculated results are compared with that obtained from reservoir simulator Eclipse™ showing a good agreement. Influential factors analysis indicates that the reduction in the ICD flow-restriction size gives an even more uniform inflow profile at the cost of reduction in well's productivity. For fractured reservoirs, the optimum well production performance is reached when the number of openhole packers is maximum, which means there is only one ICD joint per compartment. Variable ICD flow-restriction size design not only further improves the well production performance but also causes the increase in well's productivity compared with uniform ICD flow-restriction size design. Ignoring annulus flow will result in higher calculation value of well's productivity.

Optimization of the number of openhole packers in horizontal wells completed by inflow control devices for different types of reservoirs

Openhole packers are completion hardwares that are deployed as a part of the ICDscompletion system to produce a more uniform inflow profile. From the perspective ofthe operability and the economy of the ICDs completion system, the number of openholepackers needs to be optimized in order to achieve the most cost-effective completionsolution for different types of reservoirs. In this study, both steady-state approach andtransient-state approach are used to evaluate the effects of the ICDs completion withopenhole packers on the inflow equalization and the well performance optimization.The steady-state approach employs a semianalytical model that considers reservoirheterogeneity and pressure drops in the annulus, tubing, and ICDs. The transientstateapproach employs an advanced multisegment well model of the reservoirsimulator EclipseTM. The simulation results indicate that: (i) For a high-permeabilityhomogeneous reservoir, the most cost-effective completion solution should not useopenhole packers in the ICDs completion system; (ii) For a heterogeneous sandreservoir, the simulation needs to be performed in order to find the optimum numberof openhole packers depending on the degree of reservoir heterogeneity; (iii) For afractured carbonate reservoir, the number of openhole packers needs to be maximizedin order to guarantee that there is only one ICD joint per compartment.

Numerical Simulation of Erosion Wear of Liquid-Solid Two-Phase Flow in Sliding Sleeve of Horizontal Well

In recent years, the pitching sliding sleeve staged fracturing technology of open hole packer of horizontal well is widely used in shale gas, dense reservoirs, low permeable reservoirs and other exploration and development fields, and becomes the important means of present oil-gas field stimulation. But in the construction process of horizontal well fracturing, the abnormal condition that the sliding sleeve is not opened or is opened invisibly is occurred repeatedly, which has big impact on the fracturing construction. Based on fluid dynamics method and Finnie micro-cutting theory, this paper simulated the erosion wear rate of ball seat at the different fracturing segments. The results showed that: the construction displacement has big impact on the erosion wear, followed by the particle size of proppant and sand ratio, wherein the erosion wear is in inversely proportional to the particle size of proppant; and when multistage fracturing, the possibility that the sliding sleeve close to the toe end and heel happens erosion destruction is much less than that of sliding sleeve in the middle.

Intelligent Completion Inside Uncemented Liner For Selective High-Rate Carbonate Matrix Acidizing

Summary This paper describes the design, testing, installation, and performance of the first fully completed well by use of an intelligent inner completion inside an uncemented liner with openhole packers for zonal isolation. The well-design concept evolved from technical challenges associated with completing long cased-and-cemented laterals in the mature Ekofisk waterflood. The term fully completed implies full reservoir access along the pay length for production and high-rate matrix acid stimulation by use of limited entry for fluid diversion within well segments. The paper covers the development and qualification of custom openhole 7⅝-in.-liner components that can handle high differential pressures and severe temperature fluctuations of 200°F; the marriage of this complex liner with a five-zone intelligent-completion system; and results from 1 year of system-integration testing. The paper also discusses the strategic placement of both mechanical openhole and inner-string packers based on caliper and drilling logs; challenges met and overcome during installation; and comprehensive downhole-gauge data that confirms the performance of each component before, during, and after the stimulation. The Ekofisk field waterflood began in 1987 and continues to date, exceeding expectations for improved oil recovery while mitigating reservoir compaction. As the waterflood matures, new wells are more often found partially water-swept. Limited infrastructure for lifting and handling the high water production has led to increased emphasis on isolating these water-swept intervals. Cased, cemented, and perforated completions have traditionally been used for this service. Effective placement of cement is challenging in horizontals 4,000–8,000 ft in length, where rotation of the liner is not possible and high effective-circulating densities limit rates during cementing. Wide variations in reservoir pore pressures, often in excess of 2,000-psi difference along the lateral, are typical of the Ekofisk chalk and compound the difficulties of cementing. As a result, a new method for zonal isolation has been developed to ensure the success of future infill-drilling campaigns. The design and careful planning that went into the fully completed openhole uncemented-liner strategy resulted in a successful field trial and has proved this solution to be an effective alternative to cemented reservoir liners in long horizontals where zonal isolation is critical. Use of the intelligent-well system (IWS) allowed offline acid stimulation without rig, coiled-tubing, or wireline intervention. What would have traditionally been a significant water producer, with three water-swept zones totaling nearly 2,000 ft across a 4,000-ft reservoir section, has turned out to be one of the best oil producers in the field, with nearly zero water cut. Production results show high productivity with highly negative acidized-completion skins. With large investments in intelligent completions to provide zone-specific inflow control and water shutoff, isolation outside the liner becomes much more important. Over recent years, the Ekofisk wells have illustrated the difficulty of achieving effective cement along lengthy reservoir targets. The openhole fully completed solution combining an accessorized uncemented liner with an inner intelligent-completion string will allow operators to push the limits in terms of lateral length while maintaining full control over producing and nonproducing zones.

A factory fracturing model of multi-well cluster in Sulige gas field, NW China

Sulige gas field is a typical low-permeability reservoir in China. According to desert landform features along with the regional hydrologic feature and the existing fracturing technology and operational conditions, a factory-like fracturing method suitable for Sulige gas field is established to improve techniques and production organization. This method includes five key parts: (1) centralized water supply mode (water source well supply+artificial lake storage); (2) highly efficient fracturing process (two mature multi-stage fracturing technologies, sliding sleeve fracturing for vertical wells and open-hole packer fracturing for horizontal wells); (3) pipeline operation mode with seven procedures, including well drift and flushing perforation etc; (4) high efficiency operation equipment; (5) recovery of fracturing flow-back fluid. This method shortens the preparation and operation period of fracturing treatment and also relieves the pressure on environment. Pilot tests were carried out in 11 well groups in total. Sixty-seven stages of fracturing in 14 wells were successfully completed within 42 days, representing a reduction of fracturing operation cycle of more than 50%, and an encouraging improvement in efficiency.

A Fully Completed Solution With Zonal Isolation In Norway

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166209, ’Intelligent Completions and Uncemented Liners Combine To Provide a Fully Completed Solution With Zonal Isolation in Norway,’ by A.W. Kent, D.W. Burkhead, R.C. Burton, K. Furui, S.C. Actis, K. Bjornen, J.J. Constantine, W.W. Gilbert, R.M. Hodge, L.B. Ledlow, M. Nozaki, A. Vasshus, and T. Zhang, ConocoPhillips, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. This paper describes the design, testing, installation, and performance of the first fully completed well using an intelligent inner completion inside an uncemented liner with openhole packers for zonal isolation. The term “fully completed” implies full reservoir access along the pay length for production and high-rate matrix acid stimulation using limited entry for fluid diversion within well segments. The well-design concept evolved from technical challenges associated with completing long cased-and- cemented laterals in the mature Ekofisk waterflood. Introduction To improve acid stimulation and reduce casing deformation and well failures in the Ekofisk field, a new class of wells was introduced to the field (please see the complete paper for a discussion of field characteristics and associated challenges). These new fully completed wells were perforated along the entire horizontal section and used limitedentry techniques to distribute acid more evenly over the reservoir intervals. Perforations were generally spaced at one hole every 10 ft of reservoir net pay along the horizontal section, with stimulation volumes on the order of 20 bbl of 28% hydrochloric acid (HCl) per perforation. These new completion techniques proved successful in providing high-productivity completions with low well-failure rates. Post-stimulation skin values have been found to be in the -4 to -4.5 range, while liner deformation and well failures have decreased. The new fully completed designs were first implemented in horizontal wells with cemented liners, but as confidence in the designs increased, conceptual planning moved to openhole designs with uncemented liners. To improve the fully completed well designs further, it was desired to combine the benefits of a surface-operated intelligent-well system (IWS) for downhole flow control with limited-entry diversion to provide uniform acid distribution along pay intervals in an uncemented liner. This led to the Ekofisk 2/4-B-19C (hereafter referred to as the B-19C) well design. For a discussion of the functional requirements, design features, and modeling and testing of the uncemented-liner completion and all of its components, please see the complete paper. Operational Highlights The complex nature of the naturally fractured chalk in the Ekofisk field makes it challenging to predict the pattern of the waterflood, leaving the details of the final completion to be decided only after the well has been drilled. A sophisticated logging plan was implemented to characterize the wellbore better and improve hole-conditioning efforts. Among the logging-while-drilling (LWD) tools used was a deep directional electromagnetic (DDEM) tool, which helped with trajectory planning while drilling. Approximately halfway into the Tor formation, the DDEM readings indicated that the well was being drilled into the lower, wet layers of the target Upper Tor formation near the border of deeper Tor layers. After passing through a fault, higher resistivity values were seen above the well and the decision was made to increase the hole angle from 90 to 94°, steering up and into an oil-filled formation. The presence of subseismic faults and layers with high water saturations also plays an important role in the decision on where to blank off sections with openhole packers and solid liner joints vs. where to expose the liner to the reservoir by use of acid-soluble plugs. Fig. 1 shows the point at which the decision was made to build to 94° in an effort to remain in the oil-saturated Tor interval.

Fiber Optic Feed-Through Packer Technology Assists Multizone Fracturing and Production Monitoring

Young Technology Showcase Fiber optic pressure and temperature (P/T) sensing technology for multizone fracturing and production monitoring is enabled by a new feed-through (FT) technology that integrates the optical fiber within the multiple elastomer elements of a compact, swellable openhole packer system to achieve competent zonal isolation. It is important that a continuous length of optical fiber be installed across the multiple zones isolated by the swellable packer system. Splicing the fiber is problematic because the process is time c4onsuming, and the splice point degrades faster than uncut fiber. Over time, the splice presents a weak point that can limit system life. This is compounded in long, multizone completions that may require as many as 40 isolation points along the well. Weatherford’s Fraxsis FT technology facilitates deployment of continuous lengths of optical fiber across multiple zones as part of a modular packer system made up of short (24-in.) swellable elastomer sections that provide high-pressure zonal isolation. The FT technology is also a key enabler in the development of a faster, spoolable fiber deployment capability. Fiber optic monitoring of a fracture stimulation and the resulting production across every stage of the completion provides engineers with the information to improve stimulation and completion design, and optimize production over the life of the well. The FT technology enables fiber-optic monitoring using a proven packer technology that achieves high-pressure zonal isolation with a much shorter inflatable element, which reduces packer stiffness and makes the system easier to run. Technical Details The FT packer design is based on a modular approach that uses single or multiple swellable elastomer elements to create isolation points for the completion (Fig. 1). Each element incorporates a proprietary metal backup system to achieve a higher pressure rating with less than half the length of a conventional swellable packer. The metal backup system expands concurrently with the elastomer to prevent extrusion of the rubber element and form a higher pressure seal. Depending on the completion’s pressure requirements, 24-in. elastomer sections are added to the packer system to achieve 1,500 psi (one element), 3,000 psi (two), and higher-pressure specifications. As a result, the technology allows a packer only 7 ft long to seal up to 5,000 psi with the same hole-conformance of traditional swellable packers.

Advancements in Completion Technology Increase Production in the Williston Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159586, ’Advancements in Openhole-Completion Technology Increase Efficiencies and Production in the Williston Basin,’ by John Paneitz, Whiting Petroleum, and C. Christopher Johnson, Matthew White, and George Gentry, Baker Hughes, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. Over the years, hybrid systems have been installed in horizontal wellbores to increase the number of compartmental sections for hydraulic fracturing because of the limitations of ball-actuated fracture sleeves. Experimenting with hybrid systems provides operators with the ability to optimize spacing of fracture stages along the horizontal section when sleeve technology alone does not allow for the desired number of stages. The costs are higher for operators to perform a hybrid-type completion, however, and this has driven enhanced sleeve technology to allow for all-sleeve completions. Introduction The Bakken shale located in the Williston basin covers an area that includes portions of North Dakota and Montana in the US and Manitoba and Saskatchewan in Canada (Fig. 1). An unconventional reservoir, the Bakken formation is one of the last giants to be discovered in North America. The US Geological Service estimates that the undiscovered US portion of the Bakken formation holds 3.65 billion bbl of oil, 1.85 Tcf of associated gas, and 148 million bbl of natural-gas liquids. Advances in horizontal drilling of extended-reach wells and in completion techniques have increased the amount of recoverable oil and gas. Wells drilled in the Bakken are typically drilled horizontally across two 640-acre sections, with laterals that can extend more than 9,000 ft. Two completion methods known for cost-effectiveness and high well efficiency that are used in these wells are the openhole-packer system and the sleeve one-trip system. Openhole-Packer and Sleeve Completions Openhole completions performed in the Bakken are commonly run as a one-trip system on drillpipe containing the following equipment: a hydraulic or mechanical running tool, liner-top packer or liner-hanger system, openhole packers, fracture sleeves, and float equipment. Once the system is in position, the appropriate fluid is displaced, and the liner-top-packer is set; the running tool is dis-connected from the system and removed from the well. The openhole packers pro-vide compartmental isolation along the horizontal wellbore with fracture sleeves placed at each stage, forming a pathway for stimulation fluid and the production of hydrocarbons.