Below are the field cases in which applied power was reported together with the oil production increase, so that we can evaluate and compare the energy gains of the different processes tested. Comments The EG calculation assumes that the power reported is the 60 Hz power of the HF power supply. Data reported by Pizarro and Trevisan[3] Comments Test stopped after 70 days of heating because of voltage control system problems. Comments Both wells were badly sanded, and operations were suspended. There was a history of short circuits and power supply problems (casing isolation failure suspected).

Many oilfield processes normally employed on the surface may be adapted to downhole conditions. Examples include phase separation, pumping, and compression. Sometimes the design specifications for downhole processes may be looser than surface processing because control is more difficult. Partial processing, in which fluids are separated into a relatively pure phase stream and a residual mixed-phase stream, are most common. Downhole separation technology is best suited for removing the bulk (50 to 90%) of the gas or water, with downstream surface or subsea equipment being used to "polish" the streams for complete separation.

NextTier Oilfield Solutions announced today that it has recently started field testing electric fracturing pump technology developed by National Oilwell Varco (NOV). The two Houston-based energy companies are looking to the electric-based systems, also known as e-fleets, to improve efficiency and lower emissions at unconventional wellsites in the US. NextTier is currently using prototypes in the field and, if the pilot proves out, then the pressure pumper may end up purchasing the first e-fleet manufactured by NOV, the announcement said. NextTier added that its pending adoption of e-fleets would complement its dual-fuel fracturing fleets that can run on either diesel fuel or cleaner-burning natural gas. Like other commercial e-fleets, NOV's system relies on gas turbines to generate power that is then used to drive the high-horsepower pumps.

A field test was conducted with autonomous marine vehicles (AMVs) and 3D sensor arrays (3DSAs) to record and compare seismic data generated during an ocean-bottom-cable (OBC) survey. The test was a field verification to check that the AMV platform and the sensor array can deliver high-quality seismic data in a form that can be successfully processed and compared with ocean-bottom fixed-receiver data. The feasibility test conducted offshore Abu Dhabi demonstrated the successful and safe deployment, seismic-data acquisition, and retrieval capabilities of the AMV and 3D sensor array. AMVs are an alternative to conventional methods of acquiring marine seismic data; they are designed with the aim of increasing offshore safety and reducing risk while delivering a quality service within lower-cost pricing models. These unmanned vehicles have expanded the envelope of offshore operations and have been instrumental in increasing productivity and safety in marine environments.

Summary Polymer flooding is one of the most promising chemical enhanced-oil-recovery (EOR) techniques. It offers a high incremental-oil-recovery factor (IORF), low cost, and wide reservoir applicability. The first large commercial polymer-flooding application began in Daqing Oil Field and remains the largest polymer application in the world. However, encouraged by the success of previous field applications and new findings regarding the viscoelasticity of polymers in the reduction of residual oil saturation (ROS), high-concentration high-molecular-weight (MW) polymer-flooding (HCHMW) field tests have been conducted in many oil fields in China. Although some of these field tests in Daqing are well-documented, subsequent progress has seldom been reported. Moreover, recent references about the latest polymer-flooding applications in China reveal that HCHMW has only a limited application in Daqing. This is not in agreement with previous reports and expectations, especially given that viscoelasticity has been drawing increased attention. This paper explains why HCHMW is not currently widely used. New types of amphiphilic polymers are also field tested in China. Lessons learned from polymer-flooding practices in offshore reservoirs, heavy-oil reservoirs, and conglomerate reservoirs are given to help reduce risks and costs of polymer flooding in the low-oil-price era. EOR techniques in post-polymer-flooding reservoir field tests are also compared. In addition to providing useful information for engineers, this paper helps clarify some misconceptions—such as injecting the most viscous polymer possible—in polymer-flooding implementations, according to polymer-flooding practice in China. Annual oil production using polymer flooding as well as polymer utility factors (UFs) are given. Various technical parameters, such as polymer slug, viscosity, IORF, oil-increase factor (OIF), and water-cut decrease, are provided to better understand polymer-flooding evaluation as well economics.

An innovative and practical solution for well monitoring of pressure, temperature, inertial, and magnetic parameters is reported. Tiny and robust systems integrating microscale technologies for telemetry, wireless charging, and physical sensing were developed, characterized, and ultimately deployed on a live installation. The microsystems were designed and developed by the University of Michigan and characterized by Total S.E., whereas the intervention protocols were designed and implemented by TOTAL in TOTAL E&P CONGO offshore facilities. This work demonstrates how regular downhole monitoring of assets can be performed at low cost, thus optimizing production while also de-risking future development plans such as infield wells. This novel approach also reduces risks associated with conventional downhole monitoring methods.

In a Japanese oil field, which applying jet pump (coiled tubing running, standard flow type, produced oil as power fluid containing asphaltenes and waxes) since 2014, unstable power fluid injection pressure has been observed since 2016 due to asphaltene deposition on jet pump nozzle area, which limited power fluid rate and therefore production rate. The objective of this study was to achieve high oil production rate by overcoming the pressure fluctuation due to asphaltene deposition problems.

Asphaltene inhibitors (AI) from various suppliers were tested to measure asphaltene deposition amount as a laboratory screening. The best AI candidate was implemented in a field trial test during which, asphaltene deposition amount in strainers were measured, production oil was collected to measure asphaltene deposition rate under stock tank condition, and operation data was monitored and analyzed. To confirm the new AI efficiency, these data were compared with the ones during the original AI before starting the field test.

This paper presents specific features which were found in the field test. Selected AI was efficient at dispersing asphaltenes. It achieved stable injection pressure and reduced asphaltene deposition amount in production oil sample. However, it became worse again within one month. The main reason was that the new AI worked as dispersant to delay asphaltene deposition so that asphaltenes finally accumulated under jet pump production system which is semi-closed loop. Asphaltene deposition amount on strainers increased during winter, especially shut down periods, because process temperature was close to ambient condition. This temperature-dependent observation means asphaltene deposition was highly influenced by wax deposition. A follow-up laboratory test revealed the asphaltene deposition amount decreased by adding paraffin inhibitor (PI). This field test result revealed the asphaltene and paraffin interaction in field scale.

Abstract A North Sea operator had abandoned one of the inner slots of an offshore normally unmanned platform (NUI) that contained a stuck conductor, with the conductor shoe positioned 108 m below seabed at 1° inclination. Attempts to recover the conductor at the time proved unsuccessful and the slot was abandoned. However, the remaining slots on the platform were drilled and completed. With limited space and reservoir targets still to be developed, the operator later decided to use the abandoned slot to drill a production well. Given the stuck conductor and crowded platform, there were concerns for the integrity and safety of the surrounding wells. Drilling of production wells must not only allow the reservoir to be developed, but also protect the integrity of the existing wells, and proceed in a safe manner. This requires compliance with company and governmental procedures, regulations, and best practices. To help ensure safe utilization of a compromised offshore slot (i.e., with a stuck conductor) on a congested platform, drilling had to comply with the company's strict anticollision (AC) policy of isolating health, safety, and environmental (HSE) risk wells. Extensive preventive measures were executed, including shutting in high-risk wells, evaluating current and offset wellbore conditions, and selecting the most appropriate drilling tools. A custom drill bit was designed to provide the bottomhole assembly (BHA) control necessary to help minimize damage to the outside casing of any accidentally contacted well. This would further help mitigate the potential for drilling through multiple well barriers, and prevent expensive and complex remedial work. Field testing was critical to the design modifications and validated feasibility before use in the abandoned slot. These tests evaluated the new drill-bit design versus a conventional drill bit in a comparable, controlled environment.

Abstract It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to the reduced residual oil saturation, the high steam-oil ratio, and the lower profitability. A field test of CO2-assisted steam flooding technology was carried out in the steam-flooded heavy oil reservoir in the J6 block of Xinjiang oil field (China). The field test showed a positive response to the CO2-assisted steam flooding treatment including a gradually increasing heavy oil production, a rise in formation pressure, a decrease in water cut, etc. The production wells in the test area mainly exhibited four types of production dynamics, while some production wells showed production dynamics that were completely different from those during steam flooding. After being flooded by CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence could yield a stable oil production. Meanwhile, emulsified oil, together with CO2-foam, was observed to be produced in the production well, which agreed well with what was observed in the lab-scale tests. The reservoir-simulation-based prediction in the test reservoir shows that the CO2-assisted steam flooding technology can reduce the steam-oil ratio from 12 m (CWE)/t to 6 m (CWE)/t and yield a final recovery factor of 70%.

Downhole drilling motors are the workhorse of our industry and are used on almost every well drilled globally. This makes an instrumented drilling motor the perfect tool for geosteering with near-bit inclination and formation-change-detection sensors. There have been a number of drilling motors and near-bit subs designed to provide near-bit inclination and gamma/azimuthal gamma measurements over the years. These designs provide the measurements but typically compromise drilling motor mechanical strength or directional response. This paper explains a new type of instrumented drilling motor with real-time continuous inclination and drilling dynamics.

The instrumented wired motors described in this paper have taken a completely different design approach. Using already-existing drilling-motor technology, the necessary sensors, electronics, wiring and short-hop technology have been transplanted into the centerline of the drilling motor without compromising mechanical strength. In addition, the design allows for fast turn-around service times in an existing drilling-motor workshop.

Directional drillers rely on measurement-while-drilling (MWD) real-time data to maintain the well-path on trajectory or within zone. MWD measurements are taken behind the drilling motor and are typically more than 50 feet behind the bit. Real-time near-bit inclination measurements allow for more accurate and precise directional drilling. The new instrumented drilling motor delivers real-time near-bit inclination just 5 feet behind the bit. In addition, near-bit vibration measurements can be used to identify formation changes. The new instrumented drilling motor can be used for geosteering using vibration measurements.

The instrumented wired motor has undergone extensive testing in West Texas to ensure the main components are reliable and can survive harsh drilling conditions. Testing was performed in three main phases; 1) through-wire communication, 2) dynamic inclination and vibration measurements; and 3) short-hop to MWD.

When all three phases of testing were complete the entire instrumented wired motor was deployed to deliver near-bit real-time inclination and drilling dynamics measurements to improve directional drilling. The near-bit inclination measurements allow the directional driller to respond to unpredictable directional changes such as formation push and formation tracking. This provides increased accuracy to keep the wellpath in the zone of interest, particularly in lateral wellbores. This paper will detail the innovative drilling motor design and results obtained during product validation.