Limited-entry (LE) plug-and-perforate (PnP) fracture designs were pioneered in the early 1960s as a cost-effective technique to stimulate multiple pay zones with varying stress regimes (Murphy and Juch 1960). Conventional completion techniques involved blanket perforating the entire interval at a certain number of shots per foot (spf). The LE technique was revolutionary in that it recommended “limiting” the number of perforations to distribute fracture-stimulation fluids into multiple intervals with differing stress regimes. However, diagnostics have shown that LE-treatment distribution during the slurry phase is uneven, and is highly affected by several key parameters that may change significantly during treatment. Several papers have been published on the inefficiencies associated with LE design and what can be performed to overcome them (Ugueto et al. 2016; Somanchi et al. 2016).
Shell Canada Limited recently tested extreme limited-entry (XLE) designs to determine if additional pressure drop across the perforations would improve treatment distribution. Stages were alternated with differential perforation friction (ΔP) pressures of 2,000, 2,500, and 3,000 psi to determine if there was a threshold ΔP that would result in a more-optimal treatment distribution. However, because of wellhead-pressure limitations, actual ΔPs were below the design values. There were no placement issues associated with fewer perforations and higher treatment pressures.
The trial well was completed with thirteen three-cluster stages. All clusters were spaced evenly at 50 m and fracture-stimulated with a slickwater system with 31 tons/cluster (93 tons/stage). The fracture stimulation was monitored with an externally clamped fiber-optic (FO) cable. Treatment distribution and production were quantified by using distributed acoustic sensing (DAS) (Molenaar and Cox 2013).
Post-job analysis indicates a 40% improvement in distribution compared with previously stimulated three-cluster standard LE completions. With the XLE design, 100% of the clusters received some proppant. There is a 33% increase in cluster activity at IP90 (initial production on the 90th day) from the XLE design compared with a previously completed three-cluster conventional LE well. Improvement in distribution is minimal beyond ΔP of 1,200 psi during the pad phase. However, this threshold could be rock-specific and needs to be validated with trials in different play types. Data also suggest that treatment pressure should be maintained at a maximum throughout the pad and slurry placements, within equipment and wellhead limitations. During the pad, this is important to ensure breakdown and fracture extension. In the slurry phase, maximizing out pressure helps to maintain ΔP across eroding perforations.
In some plays, insufficient ΔP may prevent all clusters from breaking down. In Groundbirch, typically all clusters break down and take fluid from the start but screen out as soon as sand hits. Typically, slurry rate was not increased to compensate for the loss in ?P associated with an increase in perforation diameter. These factors are mainly responsible for the heel-vs.-toe bias in LE designs, which results in undertreatment of toe clusters (Ugueto et al. 2016).
This paper discusses a new and general method of backup-cutter layout to extend bit life without sacrificing rate of penetration (ROP) and two field-case studies. This method includes the following aspects:
• Ensuring backup cutters do not cut or only partially cut when their primary cutters experience little-to-no wear and when the penetration per revolution of the bit does not exceed an expected value. This aspect is enabled by allowing backup cutters to have a minimal critical depth of cut that is greater than the depth of cut of the primary cutters.
• Ensuring that backup cutters act as active cutters when the primary cutters’ wear depth is equal to or greater than the underexposure of the backup cutters. This aspect is enabled by allowing each backup cutter to be rotationally behind its primary cutter by approximately 150° or greater. The underexposure of each backup cutter relative to its primary cutter is calculated carefully on the basis of the primary cutter’s wear and drilling conditions.
Zhao, Chong (China University of Petroleum (East China)) | Yu, Guijie (China University of Petroleum (East China)) | Chi, Jianwei (China University of Petroleum (East China)) | Zhang, Jiaxing (China University of Petroleum (East China)) | Guo, Zhuang (China University of Petroleum (East China))
Coiled tubing is continuous thin-walled steel tubing several thousands of meters in length without screwed connections. Cyclic plastic-bending deformation occurs during tubing spooling on the reel and when passing through the gooseneck arc guide. The coupling effect of cyclic plastic bending and internal pressure causes coiled-tubing diametral growth and wall thinning (referred to as ratcheting). This paper presents a numerical algorithm to calculate the deformations of the diameter and wall thickness on the basis of the incremental plasticity theory and the principle of virtual work. It is shown that predictions with the algorithm correlate well with experimental results.
Perforation with shaped charges as a conventional well-completion technique is widely used in the oil industry. Different phenomena influence perforation performance and depth of penetration (DOP). The authors examined the effect of in-situ stresses and shot density on DOP and created fracture patterns in concrete and limestone samples with surface and polyaxial/triaxial-stress-loading conditions. To achieve this aim, we designed and developed a polyaxial-perforation test machine. We optimized the number of experimental tests using the Taguchi-design test method. The Taguchi orthogonal scheme is well-known and is a highly recommended method to optimize the number of required experiments (Taguchi 1990; Ross 1996; Jeyapaul et al. 2005; Gupta et al. 2014). Our experimental setup resembles vertical wells in the strike/slip-faulting regions and horizontal wells in the reverse-faulting regions. The results show that DOP is more controlled by stresses normal to the shooting direction in polyaxial tests than by the stress in the direction of penetration. DOP and the maximum hole diameter from the second charge had a direct relation with shot density. The DOP observed in polyaxial-loading conditions was a little lower than in the triaxial-loading mode, where the mean value of stresses normal to the shooting direction in the polyaxial tests was the same as the horizontal stresses in the triaxial tests. In both surface and triaxial-loading conditions, the patterns of perforation fractures were radial and regular, whereas the cracks created were oriented along the direction of maximum horizontal stress in the polyaxial tests.
An oil and gas operator in the Gulf of Mexico (GOM) planned to drill a deepwater well section in one run by concurrently drilling and enlarging a 12¼- to 14½-in. hole while deviating from 60 to 30° inclination and crossing expected depleted formations. At section total depth (TD), the rathole below the underreamer needed to be eliminated to help ensure successful cementing of the liner. A bottomhole assembly (BHA) was designed to allow achieving these objectives in one run, and the field results obtained with the system are described.
The first step in determining the best BHA design was to compile drilling experiences through the target formations and perform a review of all pertinent offset-well information. Weaker zones had been encountered in the 12¼ × 14½-in. section, and an at-bit reamer (ABR) had to be included in the BHA to allow the liner to be set on the bottom of the section, rather than leaving an 85- to 135-ft rathole. Because the ABR placement in the BHA is between the bit and the rotary-steerable-system (RSS) tool, it was important to ensure that directional control could be maintained in the section and make certain no interference existed between the ABR and the wellbore that could compromise control. Stabilization and placement of the underreamer were also crucial to ensure that the necessary directional performance was obtained without overstressing the BHA components, and modeling was performed to optimize the design. Hydraulics and torque-and-drag modeling ensured that the BHA design could drill the depleted zone without premature activation of either reamer.
The modeling and analysis of offset performance resulted in successfully drilling the section and opening the rathole in one run. The BHA was steered to the final desired angle, and reached the section TD without incident and at the desired rate of penetration (ROP). After the section TD was reached, the ABR successfully opened the 12¼-in. rathole to the desired 14 in., allowing the liner to be set 3 ft from the bottom. Normally, this type of operation would require a separate dedicated hole-opening run. Using the new design eliminated the additional trip and the time necessary to open the hole, which was estimated at 56 hours.
A BHA solution was developed through modeling that allowed the operator to not only maintain the steerability needed to achieve directional requirements with an ABR between the bit and the RSS while drilling depleted formations but also to concurrently perform underreaming.
Pushing the frontier of oil exploration and production into more-challenging environments and more-frequent interventions and workover operations in subsea wells has led to an increased focus on the structural integrity of a subsea wellhead (WH) and its capability to withstand the fatigue damage it will be subjected to throughout the well’s life cycle. The renewed interest led, among other works, to the publication of a WH-fatigue-analysis method statement (MS)1 in 2011, followed by a recommended practice (RP) (DNVGL-RP-0142 2015), both by Det Norske Veritas Germanischer Lloyd (DNVGL).
The MS aimed to reflect the best practices in the industry and to provide a consistent analysis procedure that would ensure the comparability of the results. However, although it thoroughly described the modeling of the WH, the MS deferred the incorporation of wellbore thermal effects, whereas the RP (DNVGL-RP-0142 2015) only briefly mentions that the effect of temperature should be considered. This perhaps responds to a lack of studies on how this may be taken into account or scarce knowledge about how the variations of wellbore-temperature distribution might affect fatigue damage on the WH.
This study describes a numerical approach to increase the scope of the current WH-fatigue-assessment methodology by incorporating the well-temperature distribution into the fatigue analysis. A representative case study of a typical drilling operation in the North Sea has served to investigate how temperature may affect the WH cyclic stresses and the estimates of fatigue-damage rates over time for different cement-sheath levels between the conductor and surface casing.
1Grytøyr, G., Hørte, T., Lem, A. I. 2011. Wellhead Fatigue Analysis Method. Technical Report No. 2011-0063, JIP Structural Well Integrity, DNVGL, Høvik, Norway. This MS has been referred to by several studies but is no longer available in the public domain.
A wide variety of annular-pressure-buildup (APB) -mitigation techniques has been deployed in the past 2 decades. In the early 2000s, BP focused efforts on the development and implementation of rupture disks, nitrified foam spacers, syntactic-foam modules, and vacuum-insulated tubing (VIT). Initiatives to simplify operations while maintaining well integrity have led to innovative techniques that expand the APB-mitigation toolkit.
BP’s Gulf of Mexico (GOM) Thunder Horse drilling team recently pursued three APB-mitigation techniques. One method is to fully cement the annulus, thereby removing the fluid that is subject to thermal expansion in a trapped annulus. A second method uses a qualified port collar to equalize pressure across a casing string. The third method focuses on better acquisition and use of mud pressure/volume/temperature (PVT) data for a more precise prediction of the APB-design loads.
These methods and techniques have led to the removal of syntactic foam from some wells in the Thunder Horse field. The design change reduces installation time and operational complexity during well construction and abandonment.
This paper provides a description and technical details concerning the planning and job execution for the fully cemented annulus and the use of port collars for pressure equalization. It also discusses the motivation behind acquiring PVT data specific to a particular mud system, and provides interpretation of laboratory data. The work may be useful for other operators as they plan and execute wells subject to the potential for APB.
The investigation of nanotechnology applications in the oil and gas industry is increasing gradually; therefore, this technology needs more exploration to unveil promising applications. In this study, an experimental investigation of nanotechnology on the apparent viscosity, viscoelastic properties, and filtration performance of surfactant-based fluids (SBFs) or viscoelastic surfactants (VESs), polymeric fluids, and SBF/polymeric-fluid blends is presented. The concentration of SBF is 5 vol%, whereas that of polymeric fluids is 33 lbm/1,000 gal guar. Besides, both fluids contained 4 wt% potassium chloride (KCl). In addition, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25 and 25/75 vol%, respectively. Nanofluids were prepared by adding 20-nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4 wt%, to the clean fluids. Apparent viscosity and viscoelastic data were gathered with a rheometer within a temperature range of 75 to 175°F, whereas filtration tests were conducted with a wall-mount filter press at ambient temperature and 100-psi differential pressure.
The results indicate an enhancement in the apparent viscosity and viscoelastic properties of surfactant-based and polymeric nanofluids up to a nanoparticle concentration of 0.24 and 0.4 wt%, respectively. Blend-A nanofluids show improvement in apparent viscosity and viscoelastic properties at a nanoparticle concentration of 0.058%. Similarly, Blend-B displayed favorable results up to a nanoparticle concentration of 0.24 wt% at temperatures of 125 to 175°F. Promising filtration results were displayed with surfactant-based nanofluids and Blend-A nanofluids at all nanoparticle concentrations, but the performance at 0.24 and 0.4 wt%, respectively, is slightly better. Polymeric nanofluids and Blend-B nanofluids revealed very good filtration results at all nanoparticle concentrations, but the performance at 0.24 and 0.058 wt%, respectively, is slightly better with a percentage reduction in API filtrate volume of 70.2 and 69.8%, respectively. A trial run was made with a commercially available fluid-loss additive [polyanionic cellulose (PAC)] in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Comparison of apparent viscosity, viscoelastic properties, filtration performance, and economic analysis revealed Blend-A nanofluid as the preferred choice.
Further, Blend-A nanofluid (at 0.058 wt%) is selected as the best on the basis of filtration performance. The selected fluid was optimized at lower nanoparticle concentrations (0.02, 0.01, and 0.002 wt%). Interestingly, using Blend-A nanofluid at 0.002 wt%, compared with the initial recommendation of 0.058 wt%, which costs USD 171.7/bbl, reduces the cost of nanoparticles required for preparing 1 bbl of this fluid to USD 5.8. Therefore, from a filtration-performance standpoint, Blend-A nanofluid is recommended for use at a nanoparticle concentration of 0.002 wt%.
The application of nanotechnology on the apparent viscosity, viscoelastic behavior, and filtration properties of SBF, polymeric fluids, and SBF/polymeric-fluid blends can deliver some benefits, if nanoparticle concentrations are selected carefully. These nanofluids will be applicable for oilfield operations such as hydraulic fracturing.
This paper proposes a tubular-design ellipse dependent on backup pressure (internal pressure for collapse and external pressure for burst), so that the latest American Petroleum Institute (API) collapse-resistance equations (API TR 5C3 2015) with dependence on internal pressure can be shown simultaneously on the same plot with the ellipse. Unlike the current ellipse used widely in the industry for casing-and-tubing design, which is approximate, the proposed ellipse is exact for collapse, burst, and axial loads. Without the proposed ellipse, use of the approximate ellipse will continue, requiring separate plots for the API collapse-resistance equations. Example cases demonstrate the advantages of the proposed ellipse, including increased accuracy. Results help clarify questions regarding the origin and use of the 2015 API collapse-resistance equations.
Propellants have been used in oil and gas wells to assist with perforating and creating near-wellbore stimulation. Propellants are electrically ignited in the wellbore at the perforated interval. Upon ignition, they rapidly create a large amount of gas, and the pressurization leads to breakdown of the formation. It has been postulated that the pressurization leads to creation of multiple fractures in the formation. This paper describes an experimental study with a new propellant and aims to understand the pattern of fracture creation with these propellants. The results are also compared with an older generation of propellant tested by Wieland et al. (2006).
A large-scale laboratory test was performed in a sandstone block (30×30×54 in.) with a 2-in.-diameter vertical centralized wellbore extending the full block height. The block was loaded in a polyaxial stress frame. A propellant cartridge was positioned in the center of the wellbore. Small holes were drilled in the rock to intersect the expected primary fracture and were instrumented with high-resolution pressure gauges to enable fracture-timing and -growth-rate analysis. Anisotropic stresses representative of field conditions were applied on the block, and the wellbore was pressurized before ignition.
The propellant ignition produced an initial peak pressure of 5,790 psi in 1.4 ms followed by an oscillatory pattern of pressure increase to a maximum pressure of 6,660 psi before decaying because of fracture growth and gas leakoff. The block was removed from the test frame and cut vertically and horizontally to examine the fracture pattern generated by the propellant. A dominant planar fracture was observed on either side of the wellbore, which propagated in the direction perpendicular to the minimum-horizontal-stress direction. It was verified that the propellant had a much-higher burn rate than the propellant tested by Wieland et al. (2006).
The large-scale block test provides critical insights and data that can serve as inputs to calibrate physics-based models for modeling propellant ignition and stimulation. The results help in understanding the benefits and limitations of using propellants for stimulation.