Vera, Vanessa (Halliburton) | Torres, Carlos (Halliburton) | Delgado, Eduardo (Halliburton) | Pacheco, Carlos (Halliburton) | Higuera, Josue (Equion Energia) | Torres, Monica (Equion Energia) | Lozano, Rodrigo (Equion Energia)
As well completions and operating objectives grow more complex, it is reassuring that certain physical parameters can be measured and predicted with extremely high precision. Precision during operational execution using real-time measurements from a customized bottomhole assembly (BHA) is a benefit offered by coiled tubing (CT) fiber-optic technology. Today marks an important milestone and basis for a new era with the development of a real-time hybrid CT service that integrates fiber-optic and electric communication and power. This paper discusses an efficient milling operation using real-time fiber optics with continuous power from the surface, referenced as the first operation performed globally.
The following three potential risks are typically associated with milling operations: CT failure attributed to cyclic fatigue loading under extreme conditions and/or exceeding the torque capacity as a consequence of the transmission of the rotational force of the motor. Premature damage to the components of the motor while exceeding the torque capabilities of the motor because of the lack of parameters at surface while milling. Motor stall that can converge into a bit-stuck scenario, or misinterpreting torque output through the motor when pumping fluid commingled with an incompressible gas.
CT failure attributed to cyclic fatigue loading under extreme conditions and/or exceeding the torque capacity as a consequence of the transmission of the rotational force of the motor.
Premature damage to the components of the motor while exceeding the torque capabilities of the motor because of the lack of parameters at surface while milling.
Motor stall that can converge into a bit-stuck scenario, or misinterpreting torque output through the motor when pumping fluid commingled with an incompressible gas.
The sum of all these conditions generated a challenging scenario. These conditions were also ideal to validate the accuracy and reliability of this technology wherein, because of downhole sensors (torque, load, and differential pressure), it was possible to monitor the milling process in real time, even when there was no detected variation in these operational parameters at the surface.
The real-time fiber-optic integrated system enables efficient, reliable execution during CT milling operations. Additional downhole insight is available with the new generation of hybrid technology for CT services, which combines fiber-optic and electric downhole powering communication. This system was designed with an open architecture to accommodate virtually any wireline or mechanical tool in the industry to address operator challenges, such as a milling operations, allowing the operator to monitor the weight on the bit, torque, and differential pressure through the bit. With the ability to constantly monitor bottomhole conditions, it was possible for the engineer to make decisions in real time, even when there was no evidence of any milling constraint at surface. Because the variables did not vary during operation, efficiency increased because of adequate optimization of the motor capabilities.
This paper explores one of the many possibilities operators have with hybrid technology for CT services, radically increasing reliability on location. This technology allowed the operator to significantly diminish operational time during milling in a single run without limitations to power or operational duration.
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
When a restriction or nonconformity presents itself in a well, quickly and reliably diagnosing the nature of the anomaly can save diagnostic runs and help prevent similar cases elsewhere, reducing nonproductive time and operating costs. Downhole X-ray diagnostics provide this understanding quickly and reliably under diverse well conditions that limit the effectiveness of other downhole diagnostic techniques. X-ray diagnostics produce real-time, quantitative two-dimensional images and three-dimensional reconstructions of downhole objects and obstructions with high precision. We demonstrate this with a case study in which X-ray diagnostics accurately identified and quantitatively characterized an obstruction due to liner deformation.
Metal expandable annular sealing systems were used in a 4 ½" completion as an effective high-pressure isolation method inside 6" open hole mudstone formation in the Foothills Basin of Colombia. Effective isolation proved to be historically difficult to achieve.
The operator was approached with a solid metal expandable sealing system with rotation capabilities as an annular barrier for a preferred cementless completion. The sealing system needed to be assembled on a full-bore liner able to deliver robust deployment with a high-pressure seal in a worse case washed-out scenario. The deployment of the system consisted of one annular barrier placed above and one annular barrier placed below the mudstone zone.
Following careful job planning with the operator, the rotationally capable completion was deployed without any incidents. To achieve pressure integrity to set the metal expandable annular barriers, a ball seat sealing system was incorporated to allow the system to be closed and the annular barriers to be set.
After putting the well onto the pipeline, the client recorded a 52% increase in their expected produc-tion from previous wells. Successful results were accomplished as effective isolation was achieved and enhanced production was obtained because of the effective stimulation. This paper overviews the appli-cation, design, implementation and results of the use of new metal annular sealing systems in a 4 ½" completion as an effective high-pressure isolation method inside a 6" open hole, drilled in fractured sandstone and mudstone formations.
During the last five years, the use of permanent downhole gauges has proliferated in the industry. The availability of true bottomhole pressure (BHP) is imperative in validating/improving reservoir models. Similarly to the extrapolation of BHP from surface readings, the use of BHP to extrapolate formation pressure may lead to significant errors in reservoir models that do not provide operators with the competitive edge needed in the current market. Consequently, there is a drive to monitor formation pressure in-situ by placing pressure and temperature gauges in direct contact with the formation.
In recent years, operators have been drilling larger holes, deploying gauge systems on the exterior of the casing, and cementing the gauge systems in place for multiple purposes. In artificial lift applications, cemented gauge systems have helped operators to avoid costs of decompleting and redeploying gauge systems on tubing whenever the electric submersible pumps (ESP) must be serviced, or perhaps whenever operators want to convert an observation well to a producing well.
In unconventional plays, technologies involving quartz pressure and temperature gauges, oriented perforating, and well conditioning practices can enable operators to deploy multiple real-time downhole pressure and temperature gauges on casing across long horizontal sections of a wellbore. This, in turn, can provide valuable production data with which to understand cluster production performance, cross-well communication, fracture azimuth, well spacing, and stage-length production implications.
Cemented gauges enable operators to understand pressure dynamics in the overburden, cap rock, or reservoir sections. The permanently installed, casing-deployed gauges connect to the surface through cable or through deployment of wireless inductive coupling technology.
Plugs for hydraulic fracturing generally are pumped into horizontal wellbores. Initially, the goal was to get the plugs to depth without careful consideration of the amount of water used in the pumping. As the industry has grown, a better understanding of pump-down methods and techniques has resulted in a realization that these pumping inefficiencies should be improved.
When completing a horizontal well using the plug-and-perf technique, water is required to push the bottom hole assembly (BHA), containing a frac plug, to the target depth. With over one million frac plugs having been pumped in North America, large data sets are available to quantify the pump-down efficiency of these operations. This past information, along with a working model of how pump down works, can be used to promote improvements in pump-down efficiency, reducing water usage and rig time.
The efficiency of the pump-down operation can be calculated based on pump time, displacement volume, and the actual volume of fluid pumped. This type of information can be recorded during operations. The pump-down efficiencies can be calculated as a percentage of actual versus calculated volumes pumped and is often expressed as a relational number, such as how much fluid is needed per 100 feet of casing. These numbers can be used as a metric for the amount of water and time required to move the plug to its desired location.
Over 10,000 frac plug pump downs from diverse North American regions were analyzed to attain a baseline for efficiency during frac plug pump down operations. The force, pressure, and fluid velocity effects acting on the BHA during pump down were analyzed to understand how to better quantify methods and designs that increase or decrease efficiency. Finally, procedures were mapped out on the operational units used in pump down to understand the potential impacts on efficiency.
The result is a guide on gauging pump-down efficiency of past operations while understanding methods to increase these efficiencies in the future. This framework can be used to view how a frac plug is pumped downhole while understanding the relationships that control its efficiency. This model can be used to evaluate past operations as well as design for future operations to increase overall efficiencies and decrease water usage and time on location.
The large independent put together a team of data scientists, software developers, and petrotechnical staff to create a forward-looking vision for how to use digital technology to solve problems. Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption.
Africa (Sub-Sahara) Oil was discovered at the Ekales-1 wildcat well located in northern Kenya. The well has a potential net oil pay in the Auwerwer and Upper Lokone sandstone reservoirs of between 197 ft and 322 ft. Tullow (50%) is the operator in partnership with Africa Oil (50%). Drillstem tests on the Pweza-3 well offshore Tanzania flowed at a maximum rate of 67 MMscf/D of gas. The tests confirmed the excellent properties of the Tertiary-section reservoir. BG Group (60%) is the operator in partnership with Ophir Energy (40%). Asia Pacific China National Offshore Oil Corporation issued a tender to invite foreign firms to bid for oil and gas blocks in the east and south China Sea. Twenty-five offshore blocks will be offered, including 17 in the South China Sea, three in the East China Sea, and five in the Yellow and Bohai seas.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).