Within the oil industry worldwide, artificial lift (AL) has become necessary to achieve desired reservoir production and maintain commercial output levels. According to Spears and Associates, in 2005, about $50,000 was spent per every new well drilled, by the end of 2016 it is expected that this figure is above $300,000. Bear in mind that this is a figure to bring things into perspective, as part of that investment is in replacing equipment in older wells, however, it does tell an important story in terms of showcasing the evident growth of the service. In an ever-evolving industry, where the ultimate goal is reducing the costs per BOE lifted, being efficient is paramount to the overall success of an operation.
According to industry statistics (Spears 2016 Artificial Lift Market Analysis), wells fitted with electrical submersible pump (ESP) systems represent approximately 56% of the global AL market revenue-wise; representing the most common lifting method, followed by rod lifting, progressive cavity pumps (PCP), and gas lift in fourth place. Just as with any complex piece of equipment, these pumps must often be pulled out for maintenance or replacement, and retrieval is not a trivial task. Workover rigs are the usual workhorse for such operations; however, other equipment, such as hydraulic workover (HWO) units, can be used to perform the same task in a more efficient manner. The evaluation approach was based on analysis from operational times throughout the past year, comparing both the evolutionary improvement of the HWO interventions as well as the operations performed with a conventional workover unit.
HWO units offer several advantages compared to workover rigs when performing retrieval and deployment of ESPs. The most important are smaller footprint and shorter rigup times. Additionally, if a well exhibits wellhead pressure (WHP), only an HWO unit can be used to perform the work. For these reasons, in land operations in western Venezuela, HWO units have proven to be the method of choice for artificial lift equipment replacement operations. Because these wells produce from 1,000 to 3,000 BOPD, they are of paramount importance to Venezuela's production stream. This paper explains the necessary steps and procedures to complete such operations; additionally presented are study results showing decreased intervention time from 15 to 11 days, which is a significant increase in efficiency. Conversely, this study showed that it takes approximately 20 days to complete the same intervention using a conventional workover unit.
Lastly described is the evolutionary path of efficiency developed by the operations team to improve intervention results, which are based on key performance indicators and other qualitative data, providing solid evidence of improvement.
This paper reviews steps taken to mitigate coiled tubing string failures resulting from microbial-induced corrosion (MIC) in the Eagle Ford by initiating an effective water treatment process alongside the use of coiled tubing with bias weld in sour fatigue similar to base tube performance.
Premature failures of coiled tubing strings can be capital intensive for most coiled tubing companies in the current oil and gas market. In 2015 there was a total of three string failures resulting from MIC in the Eagle Ford—with an estimated cost of USD 750,000. MIC has been implicated in few corrosion related challenges in the well service industry in the past.
The water treatment process was implemented in field on 21 December 2015. The mitigation process involved treating the circulating fluid in the fracturing tanks on location with chlorine dioxide, peracetic acid, or BDNP quick killer biocides. These are combined with glutaraldehyde or combination solution of glutaraldehyde and quaternary ammonium (glut/quat combo) for longer term bacterial control at the start of each job. Water samples of the circulating fluids are taken within 8 hours to get the relative light units (RLU), which determined the proper time to re-treat the water on location. RLU values were also correlated to typical sulfur reducing bacteria (SRB) and acid producing bacteria (APB) levels in South Texas. The water treatment process has been administered, along with the continuous metering of the bacteria and introduction the new coiled tubing technology, for 12 months with no string failure has been encountered. Further analysis of the effectiveness of the treatment will be conducted later in the string life when the involved strings are retired.
Every year, the complexity of horizontal wells grows, and matrix stimulation of these wells is key for maintaining production levels and improving the draw-down from producing formations. In the subject field, many wells are drilled as mega-reach with measured total depths up to 33,000 ft. The mega-reach represents a significant challenge for coiled tubing to reach the total depth (TD) and perform well interventions such as stimulation and logging. Coiled tubing (CT) may lock up before TD, and it can be challenging to understand the root cause. One difficulty is differentiating between lockups due to the well conditions and bottom-hole assembly (BHA) malfunctions.
Electric submersible pump (ESP) completions contain bypass assemblies that impose an additional challenge introducing a restriction in tubing internal diameters. The restriction is less than 2.50" in the completion, increasing to 8-1/2" for the open hole, extending for at least 5,000 ft laterally in the producing formation. With the large variation in internal diameter (ID), the hydraulic tractor option is excluded from the mega-reach aid list, though it has proven reliable in extending the reach of CT for 6-1/8" openhole sizes in the same field. Therefore, the challenge here is to derive the maximum output possible from fluidic oscillation vibratory tools to achieve forces close enough to tractor forces and ultimately accomplishing the intervention objective.
A combination of mechanical and chemical solutions was the designated approach to tackle the challenge. After reviewing all the possible solutions, tractors were excluded due to the extreme expansion ratio needed resulting in lower pulling forces. A fluidic oscillation tool inducing axial vibration of an absolute magnitude exceeding 1,600 lbf was yard tested and deployed as a solution in combination with a selection of friction and drag reducers.
This paper will illustrate the reach challenges, analysis performed, and show how we could utilize the latest developments in fluidic oscillation vibratory tools. It will also include downhole real-time data acquisition assisting the understanding of lockup occurrence, as well as quantifying the improvements in the pre-job tubing force model simulation.
Burdin, K. (Schlumberger) | Yudin, A. (Schlumberger) | Ronzhin, K. (Schlumberger) | Demkovich, M. (Schlumberger) | Kreknin, S. (Gazprom Geologorazvedka) | Pushnikov, K. (Gazprom Geologorazvedka) | Borovinskiy, Yu. (Gazprom Geologorazvedka) | Zykov., A. (Gazprom Geologorazvedka)
The geology of Eastern Siberia formations is unique. In particular, producing formations of the Chayandinskoye field have extremely low temperatures 46 -55° F (8 to 13°C). The field is currently in the exploration stage. Geological properties of the formations vary significantly, and it is necessary to define appropriate methods of well construction and completion prior to switching to a field development stage. One of the prospective options is to implement hydraulic fracturing in low-permeability areas of the Chayandinskoye. A multistage stimulation campaign was executed to test the efficiency of hydraulic fracturing in subhorizontal multilayer well. Coiled tubing was involved in operating controllable frac ports, well kick-off and inflow profile recording using proprietary technologies. The project is one of the first gas fracturing campaigns in Eastern Siberia.
The well completion configuration combined 6-5/8- and 4-1/2-in. liners, equipped with three frac ports that allow multiple opening and closing. This completion makes possible to get separate or combined inflow from producing layers. The coiled tubing fleet made several runs for frac port manipulation, wellbore cleanout of debris and residual proppant, and well kickoff until production achieved the natural flow regime.
Gas wells of Chayandinskoye field have a potential to form gas hydrates at formation conditions. Therefore, special inhibitors at high concentrations were introduced in stimulation fluid and during wellbore cleanout and kickoff. Coiled tubing minimized the hydrate issues from production start up until stable gas flow was reached. A wireline bottomhole assembly for inflow profiling and downhole pressure and temperature recording was used to obtain precise measurements of multiphase flow in the sub-horizontal wellbore. The tool was run via coiled tubing, and fiber optic telemetry transferred data from the bottomhole in real time.
The remote location of the field and limited operational timeframe due to winter road conditions generated additional difficulties in equipment logistics. As a result, the planning and preparation phases were crucial for project execution. Results have shown that fracturing as a method of field development is effective, but requires a complex preparatory stage in the laboratory and further optimization to local logistics and geological conditions. Coiled tubing services are an integral part of the completion process. By combining fiber optics telemetry and multiphase flow scanning, engineers could identify underperforming frac ports and propose prompt remedies. The technologies used in the well also enabled production testing in the exploration well in various regimes – separately from each formation, and combined. Results from the complex exploration workflow will be used to make decisions on overall field development.
Haugen, I. (Statoil) | Døssland, L. (Statoil) | Brankovic, M. (Qinterra Technologies) | Osaland, E. (Qinterra Technologies) | Osugo, L. (Qinterra Technologies) | Grødem, M. (ALTUS Intervention) | Grønnerød, Anders (ALTUS Intervention)
Barium Sulphate (BaSO4) scale is classified as a hard scale and removal is extremely resistant to both chemical and mechanical methods. Coiled-tubing deployed mechanical intervention is effective, but with inherent logistics, footprint and cost implications. Electric-line deployed wellbore cleanout systems have the advantage of being light and easily deployable. In wellbores with inside diameters (ID) of less than 3 in., removal and downhole collection of hard debris has proved to be a particular challenge.
This paper describes a wellbore cleanout operation on powered electrical wireline in the North Sea. The main operational objective was to clear out the wellbore to the top of a suspected malfunctioning Sliding Side Door (SSD), with a drift ID of 2.797 in. Access was required to run a tubing punch to establish communication with the target reservoir and therefore restore well production. The debris severely plugging the wellbore was predominantly BaSO4 scale.
Slickline broaching was initially attempted to remove the obstruction, but could not make sufficient progress. An electric-line deployed wellbore cleanout system, with bottomhole assembly (BHA) outside diameters (OD) of 2.625 in. and 2.75 in. and reservoir chamber OD of 2.5 in. was subsequently deployed, which was effective and consistently able to interact with, and remove to surface, the scale blockage. 168.6 litres of debris was collected by the electric line wellbore cleanout system.
Contributing to the success of the operation was extensive pre-job testing and measurements executed in the laboratory. These simulated downhole completion geometry and expected debris condition and interaction. The pre-job test results fed in to the design of an optimum BHA and were a basis for decision-making during the operation. The resulting system design maximised solids recovery per run, which increased cleanout and collection efficiency. A surface wellsite washout system was used to clean out the collection chambers, which enabled the rapid turnaround of equipment in-between runs.
Cleanout was executed through multiple runs, with the majority returning maximum fill to surface, which ultimately gained access to target depth as efficiently as possible. A multi-finger caliper log run confirmed the removal of the obstruction and a tubing puncher was run to perforate the inner tubing. Production was restored, with an average (over the first three months) oil production rate of 1,290 STB/D (205 Sm3/d), gas rate of 7.2 MMscfd/D (204,321 Sm3/d) and water cut of 69%.
This is the first time that an electric-line deployed wellbore cleanout system with an OD as small as 2.625 in. has delivered high, successive, repeatability in cleaning out hard BaSO4 scale from a completion with an ID as small as 2.797 in.
This paper highlights a unique technique used to overcome the specific challenge of locking open a failed-closed surface controlled sub-surface safety valve (SCSSV) in a monobore completion without a landing nipple profile above the SCSSV. The technical details of both the problem (inability to use conventional SCSSV lock open tools) and solution are discussed, with specific focus on the solution hardware and technique applied to deliver the objectives of the intervention.
Several techniques were considered and a matrix was developed to weigh the advantages and disadvantages of each. The technique selected utilized wireline to install a through-tubing expandable hanger assembly in the tubing pup joint above the SCSSV, with tubular extensions to "hold open" the flapper. The internal bore of the tubular extensions served as a conduit for the conveyance of the intervention tools required to be deployed deeper into the wellbore. This technique was successfully applied to two different wells to achieve the desired results.
The technique described in this paper for locking open a SCSSV is not limited to the monobore completion scenario with no available nipple profile. It is suitable for use on any SCSSV, regardless of the completion type or environment. This technique may prove to be a beneficial alternative when conventional lock open tools are not available or prove problematic in their application.
A defect in the surface of coiled tubing (CT) can have expensive ramifications. The defect may lead to failure in a few bending cycles and research is underway to study the influence of defects on CT fatigue strength. Existing semiempirical models are based on measured flaw dimensions and fatigue lives measured experimentally. Although the dimensions and overall flaw geometry are "known," an important feature of the flaw that has not been used is the radius of curvature at the notch root. The notch root radius is a measure of the "sharpness" of a flaw. Although empirical models assess the shape of a notch indirectly, they do not incorporate a direct measurement of the notch root radius. Since technology is emerging that is capable of measuring notch root radii, a method is needed to assess its influence on fatigue.
To assess the effect of flaw geometry, Finite Element Analysis (FEA) can be used, with sophisticated kinematic hardening rules to model the cyclic strain behavior of the material at the notch root, and reveal its dynamic behavior. However, obtaining the experimental data necessary to validate the predictions is difficult. The measurement of cyclic strains at the roots of physically small defects in CT has never been attempted due to the small size of the flaws, and limited access to them in CT fatigue testing machines. Therefore, specialized defect geometry was developed for this study specifically to accommodate the placement of small strain gages in the notch root.
Computationally intensive FEA modeling and strain gage measurements were conducted on defect-free tubing, to establish baseline tubing behavior, then repeated with the notch geometry. Strain gages had to be replaced every cycle of loading due to the large strain ranges. The tedious gage installation procedure resulted in repeatable measurements of notch root cyclic strains, and good agreement with FEA predictions was achieved.
Some additional FEA results are presented with increasingly sharper notches. Estimates from conventional notch strain analysis techniques based on the elastic stress concentration factor and elastoplastic material properties were compared to the FEA results and a modified approach was identified that agreed well over the range of geometries examined in this study.
Elliott, K. (National Oilwell Varco) | Graham-Wright, T. (National Oilwell Varco) | Williams, C. D. (National Oilwell Varco) | Hampson, R. (Halliburton) | Portillo, B. (Halliburton) | Cuaron, A. (Halliburton)
This paper presents the recent development of 140-ksi specified minimum yield strength (SMYS) coiled tubing (CT). The introduction provides background on the development. This includes the history of high-strength CT developments and potential new markets. It also defines the testing necessary to verify that the appropriate strength levels are achieved through all welding processes and compatibility with typical CT field equipment.
The tubing properties verification, steel selection process, and the welding procedure development and testing are discussed. Verification of manufacturability using current CT manufacturing equipment, which includes high-frequency induction welding, is also discussed. Compatibility testing verifies that the tubing can be used with typical CT equipment, such as injectors, blowout preventers (BOPs), and typical connections to pressure pumping equipment.
The target market for high-strength tubing is high-pressure well intervention and completion operations. Therefore, sour gas compatibility testing should be performed because even modest amounts of hydrogen sulfide (H2S) become severely sour in high-pressure environments. The testing program verifies that while using the available chemical inhibition methods, the tubing/inhibitor system is not susceptible to sulfide stress cracking (SSC), even at extremely sour H2S partial pressures in acidic environments. Finally, testing to verify low-cycle fatigue life caused by exposure with inhibition is discussed based on full-tube fatigue testing, both with and without sour gas exposure.
The paper concludes with lessons learned during the development process and presents the conclusions regarding the development, applicable markets for use, and any future steps.
Coiled tubing was utilized as a conduit-type riser to deliver high-pressure fluids from a rigless multi-service vessel (MSV) during a GOM multi-well treatment campaign. The campaign consisted of high pressure pumping into a number of subsea wells for extended durations. The coiled tubing (CT) downlines are deployed with a clump weight through open water and connected to the subsea safety module and well stimulation tool.
The depths of these operations were on the order of 1,372m (4,500 ft) and quite similar (±100 ft). Fluids (including acid) were pumped continually through the conduit at pressures up to 10,000 psi for extended periods of duration (on the order of several days) from the MSV to the fixed subsea safety module. Waves and currents impose pitch and roll on the MSV, along with the need for continual dynamic repositioning. This motion causes discrete wrapping and unwrapping at the point where the tubing just exits the sheave (the "hot spot"). This leads to elastic strain fluctuations that can lead to significant high cycle fatigue (HCF) damage.
The MSV must continually adjust its heading for optimal metocean response. A unique system was designed and implemented to coordinate this positioning with minimized CT HCF damage accumulation. The system uses a robust position transducer to provide continual input about the critical components of vessel motion. This information is used by a program to compute the near real-time dynamic stress response of the tubing at the hot spot and the corresponding HCF damage accumulation, along with the low cycle fatigue (LCF) damage accumulation that occurs along the entire length of the tubing as it is deployed during each job. The system facilitated the management of multiple jobs, assuring that hot spots were not over-exercised from job to job. This was important due to the similar depths of the wells. The hot spots were tagged with paint to confirm their location.
The mechanics underlying the fluctuating stresses at the hot spot are described along with how these are computed from the MSV motion. Post campaign fatigue testing was conducted to validate the residual life in the tubing, as predicted by the program.
Deolarte Gerrero, C. (PICO) | Sosa Barragán, C. M. (PICO) | Merchan Najera, A. I. (PEMEX) | López López, A. (PEMEX) | Ramondenc, P. (Schlumberger) | Molero, N. (Schlumberger) | Franco Delgado, E. (Schlumberger) | Miquilena Rojas, E. J. (Schlumberger)
Production in mature offshore Mexico fields is mostly driven by gas injected from surface. With time, injected gas flows directly through natural fractures in the low-pressure carbonate reservoirs, leaving oil trapped in the low-permeability matrix and reducing crude production. Over the past few years, the gas-oil contact has rapidly moved across those fields making conventional gas shutoff techniques both unsuccessful and uneconomic. An innovative approach introducing a fit-for-purpose polymer foam system (PFS) and its accurate placement using coiled tubing (CT) real-time telemetry addresses those challenges with an unprecedented success rate while optimizing both logistics and operational time.
To selectively shut off unwanted gas in these naturally fractured reservoirs, the PFS was designed to have a high foam quality and low density. Thanks to a delayed crosslinker, this formulation enables deep penetration along the fractures and fissures before the gel strength develops. To ensure effective placement of the PFS and its activation at the right depth, CT downhole gauges monitor pressure and temperature throughout the pumping stages. Any deviation from the downhole schedule can swiftly be addressed to maximize shutoff effectiveness at depth.
Monitoring of downhole parameters is not only instrumental to the PFS placement, it is also critical to other services associated with conformance operations. Thanks to the casing collar locator and gamma ray signals, it enables accurate depth control during perforating and stimulation phases. This system also facilitates the evaluation of the wellbore response after each main stage of the intervention. Finally, it can help perforate new intervals with minimum impact to the already pumped conformance treatment through the use of a new perforating firing head whose activation is controlled through fiber optics rather than triggered by hydraulics. The introduction of this methodology in offshore Mexico led to an increased success rate in gas shutoff operations. Of the nine wells that had interventions performed in 2015, eight were initially closed to production due to high gas production. Following the shutoff interventions, those wells were put back in production with an average reduction of 8.0 MMscf/d in gas produced per well and an average increase of 600 BOPD in oil produced per well. Near the end of the campaign, average oil produced per well reached 830 BOPD thanks to further improvements in the operational workflow.
This approach constitutes a significant step forward in terms of efficiency and economic sustainability. The use of CT to perform all the stages of conformance operations greatly improved logistics on the platforms. In addition, the real-time monitoring capabilities of the system and flexibility of its downhole toolstring enabled an enhanced level of evaluation throughout the interventions, which, in turn, optimized the outcome and saved days of operation.