The well discussed in this paper has a history of sand production and has exhibit long cyclic slugging behavior with a frequency of several days and reduced average production. The lower completion has a 2000-ft gap between the mule shoe and the packer that is exposed to the larger diameter of 7-in. liner. It is not fully understood whether the slugging is caused by the gap at the lower completion or by sand transportation or both.
Dynamic wellbore modelling with sand particle transport is essential to model the abovementioned complex slugging behavior. A stepwise approach was adopted to allow systematic evaluation of this complex slugging phenomenon. Initially, a lumped inflow with no sand transportation was assumed. In the next stage, sand transportation was included with zonal inflow details added. Several sensitivities on sand particle sizes, particle density, zonal productivity index, etc. were carried out, all of which were aimed at reproducing the long cyclic slugging behavior observed in the field.
Transient simulations successfully produced the slugging behavior observed in the field. Cyclic slugging was seen to be caused by the flow dynamics generated by particles of small to medium size. Some of the key findings were complete blockage by porous sand stationary bed at the lower completion gap (with subsequent pressure buildup), transition from stationary bed to moving bed, rate-dependent velocity of a slow-moving particle bed (eventually producing to surface), and fresh sand particle production from the reservoir at increased drawdown. Measured data from the sand detector confirmed the production of sand, particularly around the same period as predicted by simulation.
Potential slug mitigation solutions were established that should help to achieve higher and stable production. One solution was to achieve higher flow velocity and therefore enable sand transportation as a continuous moving bed (i.e., no blockage), such as reducing the gap size at the lower completion section together with either tubing size reduction or electric submersible pump (ESP) installation. The other solution was to implement an appropriate sand control/sand consolidation method.
Sand production is a common flow assurance issue and sometimes can result in unstable flow behavior causing reduced production. This work is the first attempt to implement particle transport modelling in transient multiphase flow simulation to successfully address a slugging issue in a real well. The analysis helped in understanding the mechanism causing the slugging and arriving at a potential mitigation solution. Further, it provides a step-by-step workflow and a template to address such problems.
In the oil sector, TOTAL should become the "low cost champion". This is presently our main challenge as mentioned by our CEO in the strategical document "One Total, our ambition". A key to succeed in a mature field such as PNGF North (CONGO) is to convert gas lifted wells into ESP activated wells. The ATEX VSD innovation consists of having the electrical module of an ESP activated well located in hazardous area, avoiding high costs that would result from a platform extension (for an electrical room). This innovation was designed by TOTAL E&P CONGO (TEPC) and installed on the YAF2 platform (YANGA field) in June 2018 has enabled to increase the production of the YAM254 well by 250% and its operational efficiency by 25 points. This innovation, which would not be possible without the close cooperation between headquarters and TEPC, could be extended to the entire TEPC subsidiary and thus open doors for new development opportunities for TOTAL brown fields.
In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
A study by a real-time monitoring company showed that many coiled-tubing strings are retired with a lot of life left in them. It suggested companies could lower costs by using pipe for a longer time and could benefit from multicompany studies showing how their decisions compare to the competition. This paper describes a methodology for classification of artificial-lift-system (ALS) failures and addition of a commonly used root-cause failure classification. The great majority of wells do not pollute.
This study presents a methodology to define the most-adequate artificial-lift technique on the basis of technical limitations, a suitability coefficient (based on an attributes table), and economic analysis toward horizontal well configuration. This paper presents an artificial-lift selection process to maximize the value of unconventional oil and gas assets. This paper focuses on a fit-for-purpose methodology to evaluate well-production performance for a wide range of artificial-lift techniques.
A common theme worldwide in the production of gas fields is the eventual requirement to deliquify the wells. Depending on depth and location, many successes and challenges are encountered. This session looks at field cases to document industry best practices, funda.m.entals and applications for gas well deliquification leading to optimal field development. We invite stories covering the widest variety of measures ranging from the most common (automated intermittent production, surface compression and velocity string) and the well specific (foa.m.-assisted lift, plunger lift) to the most advanced (gas lift, downhole pumping). Production wells in gas reservoirs with an active aquifer are vulnerable to liquid loading issues as the gas-water contact rises with depleting reservoir pressure and ultimately reaches the well.
The Production Optimisation in Gas and Oil Assets workshop is a high-quality event where experts, operators, and service companies share their latest development, successes, and failures on late-life production topics. This workshop aims to improve and accelerate the development of activities to optimise late-life production in gas and oil wells and assets. The event will include dedicated sessions on field cases of gas well deliquification, on well flow dynamics (liquid loading and slugging), on solids deposition (sand, salt, scale) and corrosion, on surfactants (both for wells and pipelines), on topside Optimisation, and on data analytics and digitalisation. Both hardware, field experience, as well as new prediction methods will be included. Technical presentations will be alternated to breakout sessions, giving plenty of opportunities for lively interaction and networking among participants.
The Production Optimisation in Gas and Oil Assets workshop is a high-quality event where experts, operators, and service companies share their latest developments, successes, and failures on late-life production topics. This workshop aims to improve and accelerate the development of activities to optimise late-life production in gas and oil wells and assets. The event will include dedicated sessions on field cases of gas well deliquification, on well flow dynamics (liquid loading and slugging), on solids deposition (sand, salt, scale) and corrosion, on surfactants (both for wells and pipelines), on topside Optimisation, and on data analytics and digitalisation. Both hardware, field experience, as well as new prediction methods will be included.
Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. This study examines how subsea processing (SSP) can develop into an important enabling technology for future ultradeepwater-field developments and long-distance tiebacks. Unconventional production patterns in the Permian Basin are leading producers to replace electrical submersible pumps (ESPs) with gas lift, which had been little used there. The sharp downturn in the offshore oil business has sparked interest in using subsea pumps to add production. If those conversations turn into orders, it may convert this rarely used option into a commonly used tool for extending the life of offshore fields.
Data-driven, or top-down, modeling uses machine learning and data mining to develop reservoir models based on measurements, rather than solutions of governing equations. Seminole Services’ Powerscrew Liner System is a new expandable-liner hanger that is set with torsional energy from the topdrive. Stuck pipe has traditionally been a challenge for the oil and gas industry; in recent years, operators have become even more determined to reduce the effect of stuck-pipe issues. The primary purpose of this study is to develop a method that overcomes the restrictions of rock-mechanics tests with respect to unconventional shale formations. The Earth is complex in all directions, and hydrocarbon traps require closure—whether structural or stratigraphic or both—in three dimensions.