Technology at OTC: Latest advances target additional efficiencies, cost-cutting

This year’s collection of new technologies and products carries on the spirit of last year’s advances, and perhaps even more aggressively, in terms of wringing out further efficiencies and cost reductions. The vast majority of offerings from the 11 equipment/service companies represented in this section fall into the drilling and completions categories, one way or another, although a couple of production-oriented items are present. Also, mirroring a trend in the industry, some items can be used onshore, as well as offshore, and a few could be described as perhaps onshore-centric, but all will be on display at OTC. WO

NOVEL PUMP DESIGN ENHANCES FRAC PERFORMANCE

A new pump has been designed to enhance pressure pumping operations. AFGlobal’s patented DuraStim hydraulic fracturing pump brings a dramatic advance in pump design, enabling next-level pressure pumping performance, Fig. 1. A radical departure from traditional triplex and quintuplex pumps, the DuraStim pump enhances performance and execution of hydraulic fracturing treatments with high-pressure, continuous-duty operation. The 6,000-hp pump greatly reduces fluid-end stress, a key source of wear with conventional pumps, with a 48-in. stroke and operating at 10% of the standard cyclic rate (20 cycles per min.). The pump triples the horsepower compared to conventional pumps while reducing the fleet footprint and manpower by as much as 65%. The result—reduced frac-spread complexity, and improved wellsite logistics and safety.

Fig. 1. New pump design adds horsepower and enhances continuous frac performance.

The pump is the industry’s first long-stroke/low-frequency, variable displacement pump. It is comprised of six individual pump units integrated by a computerized control, synchronization, and automation system that varies pump rate hydraulically. A constant speed, zero emission 6,600-VAC motor and six hydraulic rotary pumps drive the system. Electric and turbine drives are optimized by the constant-speed operation, resulting in significant gains in fuel efficiency and significantly reduced emissions and noise—85 db versus 120 db.

Cloud-enabled predictive maintenance and built-in diagnostics enhance continuous-duty operation. The novel design further improves wellsite reliability by enabling fracing operations to continue by disabling the unit that requires maintenance while pumping continues. Quick-change valve cartridges further expedite and improve the quality of routine maintenance. The company recently completed its field evaluation of the DuraStim pump technology on a three-pad multi-well zipper frac site in the Permian basin. The DuraStim ran 20 stages with no sand suspension issues.

HIGH-DEFINITION RESERVIOR MAPPING ENHANCES DETECTION OF STRUCTURAL ENVIRONMENT

The GeoSphere high-definition (HD) reservoir mapping-while-drilling service from Schlumberger is the latest addition to a technology portfolio of deep directional resistivity tools, that, to date has drilled more than 600 wells, completing more than 800 runs while serving over 100 operators worldwide.

The service’s high-definition inversion function enables better geological feature recognition in complex reservoirs, more accurate thin-layer delineation and improved lateral continuity. With the high-power transmitter and a three-receiver configuration, the technology provides a wide range of spacing and frequency to map a depth of investigation that exceeds 250 ft—the largest in the industry that covers the widest range of environment.

Due to the less than 30-sec turnaround time and 3 ft/min. real-time update rate, this cloud-enabled, fully automated solution allows drillers to continue their operations without stopping or slowing down ROP for inversion results. With the addition of 4¾-in. tool size to the technology portfolio, the new HD service provides real-time depth of investigation while geosteering in both small and large boreholes—from 5 7/8-in. to 16-in.

Fig. 2. GeoSphere HD better quantifies structural uncertainty, providing enhanced depictions of the target zone to maximize reservoir exposure.

In the Barents Sea, the new HD service clearly indicated a presence of two resistive layers, Fig. 2. The lower resistivity zone at the bottom of the section was identified as the oil-water contact and had been continuously detected all along the well section. The GeoSphere HD service demonstrated the enhanced lateral continuity of the oil-bearing sandstones from the landing until the end of the lateral section. As a result, the operator received an improved description of the reservoir along with its vertical and lateral variations and continuity.

NEW SAND SYSTEM PROVIDES INNOVATIVE ALTERNATIVE

The patented GeoFORM conformable sand management system, from Baker Hughes, a GE company (BHGE), offers an alternative to conventional sand control methods. The system uses a material that expands and conforms to complex well profiles, delivering a new level of sand control performance with fewer operational requirements, Fig. 3.

Fig. 3. A new sand control system is relatively simple to install and reduces NPT.

The GeoFORM system is run downhole like a sand screen—but it can be installed by a two-person crew, and doesn’t require special pumping equipment or proppant, making it ideal for remote locations. When used in place of a gravel pack, the new system can save one to three days of rig time per zone.

The system’s unique shape memory polymer offers three-dimensional filtration without the complexities of pumping sand slurry. Once activated, the GeoFORM material fills the annulus, filtering sand particles and stabilizing the wellbore. Its unique microscopic pore structure captures a wide range of particle sizes while remaining highly porous to maximize hydrocarbon flow. To extract additional reserves from an aging field offshore Italy, an operator had been performing conventional sidetracked operations followed by stacked cased-hole, frac-pack completions. Despite continuous efficiency gains, the frac-pack operations were too time-consuming and costly, and the system designs inherently limited how the wells could be completed. The operator opted for a new approach, trialing the GeoFORM system on a four-well campaign. Deployment and expansion went as planned, with each operation completed in a single trip, and no sand control pumping was required.

Additionally, switching to an open-hole completion design allowed the operator to avoid casing, cementing, perforating, and well cleanup operations, resulting in substantial savings. By using the system, the operator reduced operational time 40% and cut overall workover costs 35%. At the conclusion of the trial, all four wells were producing sand-free with steady gas and minimal water.

LATEST CEMPRO+ ITERATION EXPANDS SOFTWARE’S STRUCTURE, COVERAGE

Cementing is the process of displacing drilling fluids with cement slurries, where complete, durable zonal isolation is the foremost goal. The success or failure of a cementing operation can make or break the financial viability of a well or project, so it is vital to prevent mistakes and not let small problems become big ones. Proper planning and operational execution are critical to prevent cement failure and loss of hydrocarbon recovery from the wellbore.

Pegasus Vertex, Inc. (PVI) has engaged in research and software development related to well cementing operations for decades. Since its first release in 2002, CEMPRO+ has evolved into a comprehensive cementing job simulator. It distills the essence of the best R&D on cementing operations over the past 40 years. CEMPRO+ offers the industry a better understanding of fluid displacement, helps engineers make informed decisions regarding cement placement, and minimizes risk throughout a well’s life. Extensive comparisons with rig data, other established cementing simulators within the industry, and cement bond logs have helped to refine the calculations’ accuracy.

Fig. 4. The latest development with CEMPRO+ allows details from cementing previous casing strings in the same well to automatically be used as inputs for the next string.

CEMPRO+ provides a platform for both service companies and operators to ensure successful cementing jobs by putting all parties on the same page. The latest development with CEMPRO+ (Fig. 4) is centered around the structure of the software and the broadness of its coverage. With a tree structure for the wellbore, multiple casing strings from the same well can be included. This allows details from cementing previous casing strings in the same well to automatically be used as inputs for the next string. Different iterations can be run, using alternate cement compositions, stand-off values, and other inputs. Ancillary operations that impact the cementing operation, such as surge while running casing in and initial axial loads on the casing, are taken into account for the most accurate software model possible.

MULTI-MACHINE CONTROL SEES RENEWED INTEREST FOR OFFSHORE PIPE HANDLING

The multi-machine control (MMC) concept from National Oilwell Varco (NOV) allows an operator to control a full suite of pipe handling equipment as if it were one machine, with each aspect of the pipe handling process moving in a coordinated fashion, Fig. 5. MMC addresses the challenges of the modern offshore industry, which include a need to reduce operational expense in a cost-constrained environment and increase safety as processes become more and more complex. The system accomplishes these objectives by automating the repetitive and time-consuming processes of tripping tubulars, stand building, running casing, and making connections. While MMC was officially introduced a few years ago, adoption was limited, due to the economic conditions facing the offshore industry and the limited validation of the system's operational performance.

Fig. 5. Offshore operators and contractors are discovering how Multi-Machine Control allows them to control a full suite of pipe handling equipment as if it were one machine.

Recently upgraded to be more user-friendly, especially during troubleshooting, MMC is now seeing renewed interest from operators looking to increase the level of automation in their operations while delivering safer, smarter, and faster wells. NOV offers onsite training and support to build confidence in using the system and help crews overcome the challenges of changing very traditional drilling workflow models, while continued improvements in UI and technology functionality ensure that MMC is relevant to each deployment. This has all been brought together with customer leadership and a commitment to fine tuning and maintenance of the pipe handling machines, which in turn has driven increased success with MMC in recent-use cases on several offshore rigs.

“E-CHAIN” REPLACES SERVICE LOOPS ON DEEP DRILLING RIGS

Deep drilling rigs in the onshore industry are often subject to extreme conditions: Wind and weather affect the machine components. igus has now developed the e-loop (Fig. 6) for safe cable guiding of the top drive. The new modular energy chain made of high-performance plastics in combination with a strong Dyneema rope ensures a defined bending radius of the cables and withstands vibrations and shocks, all with increased safety.

Fig. 6. The “e-loop” from Igus replaces service loops in guiding top drives on rigs.

MEASURING GYRO SURVEYS IMPROVES DRILLING EFFICIENCY

Schlumberger’s GyroSphere MEMS gyro-while-drilling service delivers more transparent gyro-surveying data that increase drilling efficiency and tool reliability while improving access to small target reservoirs, Fig. 7. The new system differs from mechanical gyros in that it takes its measurements using the Coriolis effect. It uses an internal, microscale vibrating structure to ascertain the rate of planetary rotation, which varies depending on depth and latitude. That rate is then used to determine inclination, azimuth, and toolface orientation. When using the new service, the measurement is taken during connections and available immediately after the pumps are on, rather than having to wait up to 30 min. for the data.

Fig. 7. The GyroSphere service increases drilling efficiency.

Since the MEMS technology doesn't need to spin-up and stabilize as mechanical gyros do, up to two surveys can be performed in the time conventional gyros take to start up for just one. The sensor inbuilt into the technology knows when to survey and has the capabilities to report its own status. MEMS technology makes gyro surveying more efficient, and enables the service to withstand challenging downhole conditions, including severe shock and vibration. Unlike a conventional gyro apparatus that requires multiple tools, the service requires only its single sensor to survey at any inclination, at any depth, and at higher latitudes—all without the need for changing batteries or recalibrating between runs. This makes the GyroSphere service well suited for efficient batch-drilling operations.

In East Asia, the operator deployed the GyroSphere service while drilling the 12¼-in. section of the well, helping to provide real-time positioning with the same level of accuracy as drop gyro measurements. By combining the gyro surveys with the regular MWD surveys, the ellipsis of uncertainty was reduced by 40%. No additional rig time was required to complete the gyro surveys, including a full set of pull-out-of-hole survey data for QC and data redundancy. The operator saved 28 hr of rig time, and the GyroSphere service established a record for the longest gyro survey-while-drilling run ever completed.

FRACING TECHNIQUE PROPS OPEN TIGHT GAS SANDS

Tight gas sands in the Orodos and Sichuan basins of China, have historically been developed with conventional fracturing and a stimulated reservoir volume method. However, stable production is short-lived, and the stimulation effect is not obvious. To solve these issues, Anton Oilfield Services Group has implemented a full-scale hydrau-frac technique, specially for tight gas sands stimulation. The technique was developed by combining theoretical research and practical applications when treating tight gas sand reservoirs. The technique creates artificial multi-scale fractures, then fills them with proppants, Fig. 8. This technique fundamentally changes the distribution of proppant fracture morphology and conductivity, using a nano-composite fracturing fluid system (10-30nm), various fluid viscosities and controlling fracture extension.

Fig. 8. Fracturing technique using different-sized proppants efficiently opens tight gas sands.

Because the pore throat of tight gas sands is 30-900nm, the Nano composite fracturing fluid system can flow deeper into the tight gas reservoir. Using the variable viscosity characteristics of the composite fracturing fluid system, the fracture length formed by full-scale fracturing is longer compared to conventional hydraulic fracturing and produces more branching fractures. Combined, these increase the connectivity between the wellbore and tight gas sands reservoir, improving production efficiency. The fracturing fluid system is relatively clean, has easier flowback and is recyclable.

The fracing technique was applied on 11 wells in the Sichuan basin. The depth of the tight sand reservoir is between 1,800 m to 2,300 m, with a thickness of 10 m to 40 m. Porosity is 7% to 15%, with a permeability of 0.01 mD-0.5 mD. During production tests, horizontal wells fraced with the Anton method produced three to five times more gas, compared to normal hydraulically fractured wells. In vertical wells, the full-scale hydrau-frac stimulation resulted in two to three times more production, compared to conventional methods.

FLEX MPD SYSTEM

The Halliburton Flex Managed Pressure Drilling System (MPD) is a scalable, mobile technology that can be configured easily to address specific operator challenges and deliver greater rig efficiency. The tiered system allows operators to select the right level of service to maximize the benefit of MPD services, Fig. 9. It is a tablet-controlled solution with a single, straightforward display, so the driller can control backpressure or choke position while drilling, tripping and connections. 

Fig. 9. The Flex MPD system allows operators to select the right level of service to maximize the cost and benefits of MPD operations.

When additional control is required, the technology incorporates rig data for a more intelligent automated response to adjust backpressure, based on flowrates and bit depth. The system also can run as a full MPD solution, using real-time hydraulic modeling to control downhole pressure, limit formation fluids from entering the wellbore and help reduce lost circulation that can cause wellbore instability, stuck pipe and formation damage. Each tier utilizes a smaller equipment footprint, so operators can reduce rig-up and rig-down time.

NEW COMPACT MANIFOLD COMPRESSES PRODUCTION SCHEDULE UP TO 30%

TechnipFMC’s Subsea 2.0 In-Line Compact Robotic Manifold has transformed the traditional manifold design to improve subsea field development economics, Fig. 10. The compact manifold reduces size, weight and manufacturing cost. It incorporates a robotic arm for valve actuation, can be installed using the same vessel laying the flowline, and increases the flexibility for CAPEX spend over the life of the field.

Fig. 10. The Subsea 2.0 In-Line Compact Robotic Manifold is half the size and weight of a traditional manifold, compressing the delivery process up to 30%.

It is half the size and weight of its conventional counterpart and reduces cost and delivery up to 30%. In addition, its production schedule can be compressed up to 30%, providing faster time to first oil and return on investment.

The product integrates all the functions of the conventional manifold pipe work and structure into a few cross drilled blocks with integral valve cavities and common interfaces to bolt on the branch and header hubs. All hydraulic functions have been eliminated to further reduce its complexity. The result is a simpler manifold that can be produced with 10-times fewer parts, eliminating fabrication complexity. It requires no structure for support or lifting. Furthermore, production of manifolds now shifts from a customized project design to a modularized, configurable product that enables true standardization and industrialization.

The leaner, smarter manifold can be installed with the flowline by the same pipe-laying vessel, saving the need for a purpose-built heavy lift vessel.

It can be optionally coupled with an integrated robot that operates the manual valves assembled into the block. The robotic valve controller is an all-electric system operated by the topside master control station.

The In-Line Compact Robotic Manifold design is consistent with its complementary, compact products in the Subsea 2.0 platform. The result is products designed to enable predictable execution with reduced risk while decreasing engineering hours.

TechnipFMC now offers a sole source, integrated subsea solution with iEPCI, its unique approach to field architecture and project execution, along with its Subsea 2.0 platform. These technologies are setting new standards for manufacturing efficiency and accelerating delivery schedules, while reducing time to first oil.

INSULATED M-PIPE IMPROVES FLOW

Magma Global has added Shawcor’s Thermotite ULTRA insulation to its m-pipe offering. Used primarily to improve flow by maintaining the temperature of production fluids, the insulation material also can be adjusted to add weight or buoyancy to manage stability of the pipe in the water column, Fig. 11. To improve the thermal insulation properties of m-pipe, Magma identified Shawcor’s Thermotite ULTRA. It is a styrene alloy subsea insulation system designed specifically for flow assurance in subsea environments for use in ultra-deep water. The insultation layer allows the pipe to retain the ability to be transported and deployed on standard reels.

Fig. 11. Insulated m-pipe improves flow in production fluids and is designed specifically for flow assurance in subsea environments.

The ability to manage pipe stability through adding buoyancy or weight directly into the insulation material improves the potential simplicity of each design, reducing engineering and installation time on designing and building buoyancy and ballast modules. This is particularly interesting for flowlines, jumpers and pure carbon fiber riser designs. The product will first be applied in the evaluation of m-pipe jumpers in Norway. In this case, the Shawcor insulation layer is cast moulded at a 45-mm thickness, providing a U-Value of ≤ 5.0 W/m2K. This retains consistent flow temperature in water temperatures of 2°C, which is important to maintain a good flowrate and minimize build-up. Once qualified, the collaboration calls for Shawcor expertise and a cross-head extrusion line to be integrated into the main m-pipe production line at Magma Global’s manufacturing site in Portsmouth, UK. WO