Technology Roundtable: Well Completions with Baker Hughes, Halliburton, Packers Plus, Tenaris, TMK Premium-Services, Centek, TAM International & Tendeka

The key element to any well completion is the well design plan that is adopted. Would you agree with this statement and why?

Baker Hughes: The well design is a critical aspect to ensure the most efficient well completion. The optimum well design will include considerations for various different reservoir characteristics including the drive mechanism, anticipated production rates, the composition of produced hydrocarbons, and any sand control requirements. It is also important the ensure that the well design process has thoroughly considered any planned stimulation programs as well as any workover operations that are anticipated throughout the life of the well. Baker Hughes understands this relationship between the reservoir and how a properly designed well plan and completion is essential to maximize the recovery of each field. We continue to invest heavily in our reservoir development services as we support our clients with their field development plans.

Halliburton: The key to any well completion is the ability to plan with the goal of the well (or field) in mind. Having this information at the start of a project is crucial since this will dictate everything from what the primary function of the well is, the equipment that is required, and any future modifications that would be made to the well over time. This will allow for the proper funding to be allocated and the necessary equipment and materials (high end or low end) to be employed to achieve the necessary return on investment to make a well (or field) a viable business venture. Not having a clear well design (or field design) makes it very difficult to select the necessary completion.

Packers Plus: After a well is drilled, the operator will decide if it can produce oil or gas profitably. To ensure this profitability, the well must be completed properly. This process requires professionals, such as geologists and engineers to review reservoir data. These engineers will also need to forecast how the reservoir may change over the productive life of the well. The completion will then be designed for optimum production at minimal cost.

TAM International: Yes, however the statement is very broad since well completion is only one of the components to the well design plan. The well design takes into consideration the objective of the well: injector, producer or monitor well. For example, in the well design of a producer well, the life of the well is taken into consideration for current production and long term for remedial work as well. A flexible well design provides multiple options including whether to perform isolation of zones, install bridge plugs, etc.

What are the key factors for a completion design that will help operators reduce the overall costs associated with the well?

Baker Hughes: It is important that the completion design has incorporated adequate flexibility to reduce the cost associated with the installation of the completion and any potential workover operations anticipated later in the life of the well. The simplicity of the completion design, the selection of reliable components, and the anticipation of various operating conditions (stimulations, workovers, etc.), are all important to optimize the lowest cost completion design that will perform as designed throughout the entire life of the well.

Halliburton: Eliminating Non Productive Time (NPT) from operations is the major driver behind reducing overall costs on a well and can be accomplished by effectively planning and preparing the job with all parties involved in the operation. It is important to understand what services will be required in order to minimize down time at the rig. People and equipment sitting idle on location, is the largest driver behind increased well operating costs. Having an effective rig program that includes contingency operations (based on problems the formation has presented in the past), and that is reviewed with all service companies involved, is the best approach for cost reduction.

Packers Plus: One of the most critical factors is to look beyond the initial completion operation. It is not uncommon for a completion design to be based upon the benefits it provides during the completion operation itself. Often, the completion is designed by one group without due consideration to the operation of the well in the future.

The drilling aspects also need to be considered. Sometimes, a more complex drilling operation is needed in order to maximise the production or water injection. The risks all have to be weighed, but taking the easiest route does not often equal the best result.

TAM International: Simplicity and reliability. The design should be aimed at getting the most oil and/or gas production over the life of the well to increase ROI. Understanding the reservoir flow characteristics, fault placement, and where water or gas encroachment may incur during the life of the well is critical in production optimization. Placement of inflatable or swellable packers for zonal isolation, while maintaining a large internal diameter of the completion, allows for low cost remedial work over operations.

What is the most common completion that is seen in the Russian Market? Is this trend continuing or is there a change in approach?

Baker Hughes: There are many different types of completions currently being utilized in Russia as there are significantly different types of reservoirs being developed in the various regions. The Russian market has been historically dominated by oil wells completed with electric submersible pumps, however there are many challenging gas fields in Russia that offer unique challenges due to their high pressures and hostile environments.

Many Russian operators are becoming more adoptive of newer technologies as they begin to develop many new challenging green fields while also looking to rejuvenate the more mature brown fields. These technologies include multiple zone completions with downhole gauges to provide valuable production data, multilateral wells, and completion equipment that can enable multiple stage fracturing techniques to significantly improve the production and recovery from some fields.

Baker Hughes Frac Point open hole multi-stage fracturing system has been deployed recently in Russia to improve the recovery from horizontal wells. We continue to develop many new advances in this technology that allows more fracturing stages to be pumped with our system and to also reduce the time and associated risk with clean out operations after the fracturing operations.

Halliburton: The majority of the completions in Russia are ESP (Electric Submersible Pump) completions. There is a growing interest in horizontal completions that allow for more contact area in a given reservoir and allow for compartmentalized zonal stimulation. There is also more interest in the sand control technologies that can be used in unconsolidated reservoirs to prevent the costly sand influx. Intelligent completion technologies are also gaining ground as the benefits of having real time control of the components down hole are being recognized by the oil companies.

Packers Plus: From what I have seen to date, a single vertical well, cased and cemented with a single proppant fracture is very common. The upper completion is often an Electric Submersible Pump (ESP). However, the trend is changing to horizontal wells with open hole reservoir sections and multiple proppant fractures. It would seem that the number of wells drilled cannot really increase, so the only way to improve production results is to improve each well’s performance.

Not only is reservoir contact and production being increased due to the additional fractures gained from multistage fracturing in horizontal wells, but the cost is less than placing the same number of fractures in multiple vertical wells with single fractures. At the moment the well costs are inflated due to the testing and monitoring being implemented in trial horizontal wells in order to gain sufficient knowledge to move to larger scale field development. At that point, well costs will reduce and customers will truly start to see the benefits of open hole, multistage fracturing.

TAM International: Most Russian wells utilize cased hole completions limiting the production flow rates and remedial work over options.

What effect does the wells type (production, injection or both), run life and production level have on the completion design?

Baker Hughes: The type of well has many effects on the completion design including size of production tubing, metallurgy selection (injector wells tend to be corrosive, erosion issues, etc.), selection of completion tools based on the well conditions due to cooling/heating effects and corresponding tubing movement analysis, the type of packer selected will depend on the tube move and preferred setting method (verify the well conditions and the packer’s performance envelope). If multiple zones are to be completed, a thorough analysis must take place when selecting well control and flow control equipment (chokes for zones that need regulation, injection or production, intelligent well systems, etc.). It also has effects on the selection of the safety systems if needed since it must withstand the corrosive environments and also able to work with the supply pressure limitation of the surface control panel and umbilical.

Halliburton: For any completion the driving factor on the approach is the overall economics of the well (return on investment). Metallurgy, elastomers, ratings, etc. are all selected based on the preferred life of the equipment, which all comes back to how long a well needs to be in use in order to be profitable. Understanding the intent (production, injection, or a combination of both) determines what conditions the equipment will be exposed to and to what extent it must be designed.

Packers Plus: The drilling, completion and stimulation operations must be designed to meet the well’s purpose. A common issue we run across is completion designs that are sub-optimal for stimulation. The usual cause is that the design work is performed by people who are not familiar with stimulation operations. For example, if packers are selected purely on their ability to hold a certain pressure, it may severely affect the ability to properly place fractures. If the completion engineer does not account for the massive cooling effects that take place during stimulation, the packers selected may lose their sealing capability, which can lead to inefficient stimulation and premature screenout. This can result in costly coiled tubing intervention and poor production performance or worse.

TAM International: The type of well and the pressure and fluids that are encountered must be completely studied and understood in order to develop the optimum completion design.  Lifetime design is a key component to minimize operating expenses.  Extra consideration is needed if a producer is to be converted into an injector. In smaller internal diameter completion strings there may be restrictions to the production flow creating limitations to the selection of tools for performing reservoir testing and well maintenance.

With open hole completions, what steps should you take to minimize formation damage?

Baker Hughes: The selection of a properly formulated and engineered drill-in fluid is key when drilling an open hole section to reduce formation damage. In addition special drilling (i.e. drilling near balance) and completion techniques can also minimize formation damage and prevent lost circulation on producing zones. When properly selected and applied, these drill in fluids and drilling/completion techniques can result on higher production rates.

Halliburton: Openhole completions are gaining ground globally and ensuring that formation damage is minimized is very important to getting the desired production from the well.

The drilling practices and fluid systems that are employed need to be reviewed and understood by completion engineers just as is the completion being run needs to be reviewed and understood by the drilling engineers and geologists. Discussions surrounding the necessary steps to run an openhole completion must happen to ensure that any facts required to get the completion on depth and any best practices (i.e., special low viscous fluid system) are known.

Packers Plus: Open hole, multistage completions by their nature reduce formation damage. In a cemented completion, the entire reservoir section is isolated except for the perforations. The perforations will likely have caused local damage, so at this point you are not really left with much reservoir contact at all. Of course, stimulation can then bypass the perforation damage but you have still isolated 99% of the wellbore with cement.

Second, the typical ball-drop method of stimulating in open hole allows for a much quicker stimulation operation. A 5-stage “plug and perf” job may take 15-20 days, whereas the open hole, ball-drop method can take 2 to 5 days depending on wellsite stimulation resources and local infrastructure. The result of this time savings is that the stimulation fluids, which will cause reservoir damage over time, are on the reservoir for a significantly shorter period of time. Quicker flow back of the stimulation fluids will lead to increased recovery of stimulation fluids and reduced formation damage.

TAM International: To minimize formation damage utilize open hole completions, rather than cement and perforate.

Multilateral wells require more complex completions. What solutions do you have for this area?

Baker Hughes: Multilateral wells can range from the very simple completions similar to running a liner hanger to very complex completions that allow remote monitoring and control of the well bores. Baker Hughes offers the industry’s most diverse multilateral tools portfolio that covers the entire range. Our wide array of multilateral junctions, completion tools, and accessory equipment can satisfy all of your production and operational needs. Our HOOK Hanger systems utilize the same standard running procedures and techniques as running a liner hanger. They can create TAML level 3, 4, and 5 junctions, allow positive re-entry into all bores even in stacked applications, and are compatible with multiple stimulation operations including high pressure hydraulic fracturing for unconventional reservoirs. Our RAM system can be used to rotate liners to depth in difficult or extended reach applications. Our HydraSplit system offers a reliable hydraulically isolated junction with large ID access and re-entry to each of the wellbores.

Halliburton: Halliburton has a group dedicated to multilateral wells who are responsible for the recommended drilling and completion equipment needed to achieve the desired multilateral well design. The technologies that are used range from pre-milled windows and latch couplings used for the drilling of the well, to Swellpacker® isolation systems and SmartWell® system technologies for completing the well. The exact technologies used are dependent on the desired well functionality and can be as simple or complex as necessary.

Packers Plus: We have a number of options for completing multilateral wells with open hole, multistage system equipment. We have a very good installation history in this area (>500 legs), and dual-leg wells with 8 to 16 stages in each leg are not uncommon. It is a very good way to increase reservoir contact from a single surface location. The stimulation operations are no more complex than a well with only one lateral.

TAM International: The use of the inflatable casing annulus packers or swellable packers can be used to provide zonal isolation required in the vertical wellbore; they can also be used to create compartmentalized zones in the lateral itself. Swellable packers can be particularly useful by eliminating the need to cement. When performing open hole completions in multi-lateral wells isolation of the junction is very important in the stability of each lateral.

Well integrity is the primary function of the completion. How do you test the initial completion and what tools can you use during the well’s life to ensure integrity?

Baker Hughes: The industry defines well integrity as the “Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well”. Well integrity involves accountability/responsibility (who owns it), well operating processes, well service processes, tubing/annulus integrity (at production packers or liner top packers, etc.), tree/wellhead integrity and testing of safety systems. Many tools are used during the testing but includes surface hydraulic pumps, valves, pipes and fittings, stand valves and slick plugs and various accessories to test safety valves and sliding sleeves (separation sleeves, etc.).

Packers Plus: The open hole, multistage system completion is designed with the ability to provide well integrity when it is required. The completion can be tested once it has been set (packers engaged) by performing a tubing test and also annular tests on the liner hanger. The well stays mechanically isolated until it is time to stimulate. Post-stimulation, individual stages or the entire completion can be closed in on coiled tubing using the appropriate shifting tool. This functionality can also be used to re-frac individual stages or the entire well if required.

TAM International: Testing the initial completion depends on the type of completion, for instance a slotted liner is pretty much installed and then the well treated and/or placed on line. However during the life of a well different casing/liner sections may require that periodic mechanical integrity tests be performed; a multi-set inflatable packer is ideal for casing pressure tests in this case.

Well control is paramount at all times and it is a vital component of the completion to prevent the uncontrolled release of hydrocarbons. What are the key factors for safety valve selection and positioning in the well?

Baker Hughes: Key considerations include deployment method (tubing or wireline retrievable), profile in the top sub of safety valve (for landing accessories), tuning size, seal bore size (under tugging drift), OD (to fit in casing) thread type, setting depth (API recommends for offshore wells at least 100 meters below the mudline or the most appropriate depth to prevent asphaltenes or scale build up), working pressure, temperature rating, metallurgy, thread weight and type, and specify the need for cable bypass/protection.

Halliburton: Safety valves are available in both tubing-retrievable and wireline/slickline-retrievable systems, equalizing or non-equalizing, corrosion resistant alloy or standard materials, general production or deep-set / high pressure high temperature. In order to properly select a safety valve, the well conditions must be known, in addition to anticipated production pressures and rates, required open and close pressures, etc. There are a wide range of valves to suit all applications and provide the well control required in the event of a catastrophic event.

TAM International: The type of service a safety valve is going to be exposed too and the anticipated pressure that could be encountered are what should determine which type of safety valve is used. If it is sandy service, H2S, high CO2, or other corrosives environment it is important to make sure it will meet these requirements. It must be able to handle cycling for the life of the well, in which it is function tested at least once a month to make sure it is operating correctly.

The method of operating the valve will impact the positioning. Most safety valves are placed a minimum of 90 ft (30 m) below the mud line, with a landing nipple profile placed either directly on top of the SCSSV or 30 ft (10 m) above to allow a secondary safety valve (Wireline or Coil tubing) to be installed.

Casing/Tubing:

What advantages do premium casing connections have over standard API / GOST pipes, and what are their benefits for drilling contractors and operators?

Baker Hughes: Premium connections are designed with metal to metal seals and do not rely on the threads and the thread compound to create a seal. Premium connections are generally machined to very exacting standards ensuring proper thread engagement and a good metal to metal seal.

Premium connections are generally designed with much higher strength characteristics than other connections, this can be important for deep wells, high pressure and high temperature wells or for wells that are deviated where the stresses on the connections may be much higher.

In general it can be said that premium connections are used in most offshore wells worldwide because of the extra protection that they provide. It is also highly recommended that premium connections be used in any gas well applications.

While installing casing and tubulars with premium connections it is strongly recommended that a adequate torque turn system is utilized to ensure the proper installation. It is also recommended that an appropriately sized power tong with an integrated hydraulic back- up be used. Baker Hughes utilize our “Salvo” system, to monitor the make-up of the connection and to record the final torque achieved and other parameters that can then be kept in the well records.

Tenaris: API/GOST pipes are typically used in conventional string designs, for shallow well applications and are older, more established technologies. Premium connections, however, incorporate state-of-the-art engineering design and have been specially manufactured for more complex loads and sealing requirements, such as those found in high pressure, high temperature or extended reach wells. Tenaris offers a comprehensive range of high performance TenarisHydril premium connections for challenging applications. Our WedgeTM and Blue® Series connections along with our Dopeless® technology help minimize risk and make operations more efficient.

ТМК-Premium Services: Using casing and tubing pipes with Premium-class threaded connections during the well construction has to be justified, considering that their cost is much higher than that of standard pipes with threaded connections by GOST R 53365 and API Spec 5B. This is firstly due to a longer production time and control of threading, secondly, to costly testwork for compliance with ISO 13679 requirements and thirdly to special finishing of the threading surface. This is why casing and tubing pipes with Premium-class threading connections are generally used in:
» presence of aggressive corrosive components such as hydrogen sulphide or carbon dioxide in well production;
» high gas factor in well;
» during the construction of deep wells and wells with long horizontal sections;
» during the construction of offshore wells.

TAM International: The use of certain types of premium connections on casing provide higher tensile and compression ratings along with higher torque loads for situations where rotation of the casing or bending moments may stress the connections creating leaks. Higher torque values are critical for success in some horizontal wells. Premium connections will also provide gas tight seals.

How can the casing connections aid operators drill deviated and extended reach wells?

Baker Hughes: For deviated and extended reach wells premium connections are recommended because of their higher strength and better sealing capabilities.

Tenaris: Operators can encounter several problems while drilling extended reach wells such as high loads with the need to push, bend and rotate the string into place. TenarisHydril premium connections can make significant contribution to successful operations in deviated and horizontal drilling projects. TenarisHydril WedgeTM Series flush and semi-flush connections are especially suited for these applications because they balance reduced clearance and high compression resistance. Just as importantly, given that the opposing flanks of the dovetail WedgeTM threads simultaneously engage, they are able to withstand extreme torque.

Reducing time for drilling operations is another key factor to take into consideration. Fast running jobs are imperative in horizontal wells for technical reasons, as the risk of an open hole collapsing is higher than in a vertical one. By choosing Dopeless® technology, Tenaris’s proprietary dope-free coating, operators save time on the rig. The Dopeless® coating is applied at the mill in a controlled industrial environment, eliminating the need to apply dope at the rig site. Operators in Russia and the Caspian Sea region are already experiencing the benefits of Dopeless® technology for offshore and Arctic environments.

ТМК-Premium Services: When running casing strings into wells with long horizontal sections, the running is impeded with significant friction forces, which can be minimized with special lubricant additives to the drilling fluid, but this is often not enough and the string has to be rotated and burdened with additional weight load. In this case, special premium insistent connections, which have an internal stop that does not only provide integrity in couplings, but also allows to withstand significant compressive loads and high rotation torque.

TAM International: Using premium casing connections allow for better equivalent circulating densities (ECDs) in mud removal for performing cementing operation of the casing strings. The premium connections offer higher bending and torque rating which assist in passing through high dog leg severity or short radius well bores. In some extended reach wells or horizontal wells, rotation is required to reduce friction in order to install a casing string. The amount of torque required to do this usually requires a premium connection.

What are the key considerations for operators when selecting tubulars for their offshore drilling programs?

Baker Hughes: Certainly for offshore operations careful planning of the design of the casing strings is needed for their tensile, torque and burst strengths as well as other parameters. For the supply of suitable casing and connections it is best to rely on one of the major manufacturers who have a strong reputation in this field. It is also essential to source float and stage equipment and other accessories with matching connections.

Tenaris: The first factor to take into consideration is the environment. The Macondo case has shown how extreme the consequences of an offshore failure can be. Also, in many parts of the world, local governments impose strict regulations on drilling operations to limit the environmental footprint. When operating offshore, customers need to choose reliable, field proven products to minimize risk and costly workover operations as well as guaranteeing the safety of everyone on the rig.

When choosing Dopeless® technology, the operator is relieved from performing a number of connection doping and cleaning tasks during the running preparation phase. Dopeless® connections require less people on the rig floor, reducing the chances of potential accidents and making pipe running operations safer. Since connections arrive rig-ready, much simpler and faster running jobs are attained. Also, the uniformly applied dry coating consistently generates very stable make-ups. Thanks to the increased galling resistance provided by Dopeless® technology, operators are more likely to experience a smooth running operation, significantly reducing the risk of connection damage. This technology debuted in Norway in 2003, home to the strictest drilling regulations worldwide.

Tenaris offers many services to contribute to the successful execution of offshore operations. Our technical sales team can provide string design and material selection services. We can provide logistics services to guarantee products are available when needed. Tenaris can also deploy its field service specialists to support the running and help guarantee the correct installation of the casing at the offshore platform.

ТМК-Premium Services: Offshore wells call for a number of special requirements to the piping and downhole equipment:
» first of all, the connection of casing pipes must have metal-to-metal sealinig and coupling must be 100% effective;
» connections must comply with requirements of ISO 13679 standard, level САL-4;
» services available on shore.

TAM International: The mechanical properties – burst and collapse pressure ratings, tensile strength, thread connections, corrosion resistance, metallurgy, availability and cost.

Cement:

A good primary cement job is essential to ensure long term well integrity. How do your products achieve this?

Baker Hughes: To ensure long term wellbore integrity, the cement design must address both the chemistry of the slurry design as well as the physical placement of that slurry into the wellbore. Baker Hughes cementing products allow modification of the slurry properties to address the individual wellbore conditions for each application. From materials that can prevent gas migration to those that modify the long term mechanical properties of the set cement are carefully applied where appropriate to the cement designs. Spacers designed to remove the drilling fluid and prepare the wellbore for cement are key to the overall cement job design. Coupling the slurry and spacer designs with the use of Baker Hughes state of the art cement placement modelling assures the total job design addresses all critical factors including centralization, pump rate, pressure control, etc. to assure long term integrity for each job.

Inflatable products can also enhance a standard cement job by providing specific points of isolation. An inflatable packer element will completely fill a washed out, irregular hole and provide a pressure seal against the formation. Additionally, swellable packers can be cemented around as a means of short term cement enhancement and also provide a long term solution to hydrocarbon migration through micro annulus fractures

TAM International: TAM packers are run to complement the cement job. When using an inflatable packer on the casing string that is being cemented, the placement of the packer is determined by what the customer wants to achieve, whether it is to prevent gas migration, prevent gas cut cement, isolate a loss circulation zone, address micro annulus formation, enable multi-stage cementing, or prevent channelling due to poor mud removal, etc. Swellable packers have also been shown to enhance primary cement jobs in a number of ways. They are used to prevent micro annulus problems and assist in protecting the cement sheath from being damaged during casing pressure tests.

What advantages does cement have over swellable solutions?

Baker Hughes: Properly designed and placed cement slurries can provide wellbore isolation throughout the entire wellbore. Unlike mechanical means like swellable packers, cement is not limited to specific locations within the well. To be effective, the swellable packer must be placed in a specific location within the wellbore, and can only provide isolation in that specific area. While effective in providing a localized seal, many designs call for coupling the use of swellable packers with cementing to assure total wellbore isolation.

TAM International: It is readily available on most locations, simple to use and accepted by industry. Cement will protect the outside of the casing from corrosion over intervals where this may be a problem.  Cement will also help support the casing from high internal pressures, whereas swellable packers would not be able to.

Russia is about to embark on significant offshore exploration and production. How will the offshore market affect the products that Russian’s are familiar and comfortable with using?

Baker Hughes: The cementing products and systems used in the offshore environment will still be familiar to those currently used in Russia. The difference will be some of the additives may now be supplied in their liquid form rather than dry, allowing ready modification of slurry properties without the need for shipping a new dry blended system to the rig.

TAM International: Currently TAM products are being used in Russia, both swellable and inflatable packers, for both land and offshore operations. Recent annular gas migration problems in the Gulf of Mexico and elsewhere show that additional mechanical barriers should be utilized on each casing string to prevent environmental disasters due to unforeseen occurrences.  Hurricanes Katrina and Ike certainly exposed these problems.

Swellables:

Many industry veterans are familiar with cement over swellable elastomers. What benefits do swellable solutions bring compared to cementing?

Baker Hughes: Unlike cement, swellable packers provide a means of long term annular isolation that is not prone to failure due to micro annulus fractures resulting from temperature or pressure induced tubing movement. Also, swellable packers are much more economical and operationally efficient than cementing.

Swellable packers can give an additional assurance of a seal at a specific location in the well, and do not have the associated rigorous testing required for cementing. Swellable packers can be placed virtually anywhere on the casing string, yet are limited to some extent by the fluid environment and temperature.

Halliburton: Cementing will always be an important part of the well construction process for some of the casing strings. Swellable products can provide a means of complementing a cement job (i.e. can be used in conjunction with cement as insurance against production up a mud channel micro-annulus). Also Swellpacker systems can be used when openhole completions are required and isolation is needed. Swellpacker systems provide an effective seal in the presence of the swelling medium that is required (oil or water). Swell times can be engineered through the elastomer selection and application of delay barriers.

TAM International: Swellable packers promote simplicity, reliability and provide a level of insurance against well integrity issues. In open hole completions there are two valuable benefits: 1) in soft formations the productivity index is enhanced due to exposure of the entire sand face to the pressure draw down and 2) in productive fractured formations naturally occurring fractures are not covered with a cement sheath. Swellables are essential for newer technologies such as ICD’s and will play a large role in Advanced Well Completions that require down hole instrumentation. Swellable packers also complement the cementing operations in preventing micro annulus and other problems as described in #12 above.

Tendeka: Swellable Packers are a disruptive technology, they are simple, efficient and reliable. The first water swelling packers came from a major operators R&D department in 2001 and are licenced to Tendeka (Osmotic water swelling packers). Oil swelling packers arrived a little later and both are offered, with each having distinct applications.

The combination of long liner sections, complicated cement jobs and expensive perforating equipment makes liners with swelling elastomer sections and flow control equipment a very cost-effective alternative. This technology has seen a major uptake both in fracturing of low permeable formations such as shale plays and in high permeable sand stone reservoirs. The technology has replaced many of the alternative devices such as inflatables or mechanical Packers.

Cementing and perforating long horizontal zones often proves problematic, either with losses occuring or water channelling during production (micro annulus) caused by thermal dynamic expansion, contraction and expansion of the liner or the loss of hydrostatic pressure when the cement gels.

Major Service providers are beginning to offer cement impregnated with swellable compounds to augment the cement bond and prevent water channelling.

Are swellable solutions as equally applicable in the offshore sector as onshore?

Baker Hughes: Swellable solutions have been used primarily for zonal isolation in onshore open hole completions; however, there is a growing trend to utilize them in a number of key offshore applications as well. In general swellable compounds are composed of the same proven elastomers used in virtually all other oilfield sealing components, and have been rated to as high as 10,000 psi at 400F in some applications.

There are no additional limitations to the use of swellable packers in the offshore environment when compared to onshore. The only differences would be in the design of the packer to properly address the specific environment found in the offshore well.

TAM International: Several deep water operators now use swellable packers on several of their casing strings as a secondary barrier for liner top packers, secondary/tertiary barriers to cement, or micro annulus barriers to prevent gas migration. The regulations for the offshore environment typically favour cementing, but they will eventually catch up.

Tendeka: The veterans are coming around on this issue. Swellable packers are applicable both offshore and onshore and are purely a well construction medium with multiple uses, including well integrity and the onshore shale frac market. Swellables compete directly with cementing and perforating technologies for multi stage fracs and offer significant cost benefit advantages. As an example –  with swellables you run the completion, wait for the swell and frac all zones (20 stages) in the well.

The alternative is to cement and set a composite plug, perforate, frac and then set a composite plug and repeat this process for all 20 stages. This keeps the expensive frac crew on the well site for extended periods of time during the plug running and perforating.

Some swellable elastomers are activated in water and others in oil. What are the key applications for each type?

Baker Hughes: The applications for the two base elastomers are essentially the same; however, selection is typically based on specific operational parameters such as bottom hole temperature, the wellbore fluid during deployment, and the completion fluid selected. That being said, oil-swell compounds are utilized more often in high temperature and pressure applications as they are often rated to higher temperatures than water-swell compounds.

The choice of which elastomer to use in a particular well will be one of the key design elements in the job design. Selection of which elastomer to use will depend on the fluid environment in which the packer will be used. Some wells incorporate dual systems, using both types of elastomers.

Halliburton: Oil-swelling or water-swelling packers can be used in any well; the key is to understand what conditions are required for the packers to function properly. In the event a water zone needs to be isolated, it would probably be the best application for a water-swelling since there is a continual supply of water that could be used in the swelling process and no additional fluids would be needed to be pumped downhole to aid in the swelling process. The same would apply in the situation where an oil formation is present.

TAM International: TAM has multiple rubber compounds so that the elastomer is designed to the operator’s fluid program; the completion/well bore fluid determines which type of swellable elastomer is run. We provide swellable packers for both oil and water environments. The most common use of the oil swellable elastomer is in zonal isolation where hydrocarbons will be acting on the elastomer. But, they are used just as well in drilling environments where oil base mud or synthetic muds are used. The water swellables are commonly used in injector wells, water base mud systems, geo-thermal applications and steam injection or SAGD operations. If the type of well fluid is unknown, then a hybrid elastomer can be provided that will swell in both oil and water.

Tendeka: Tendeka are the market leader for water swellable packers and offer high performance oil swellables for a cost effective performance in most well environments. Tendeka have installed more than 8000 packers worldwide with no reported failures to date.

The packers (oil or water swell) are selected for the environment in which they are exposed, e.g. for water injectors, a water swellable is used, for producers water or oil packers are used. The water packer is used to stop water migrating between producing zones (compartmentalization), and in some cases oil and water combinations are used for a complete solution.

An alternative strategy is to select a water/oil swell based on the drilling fluid used to run the liner. As an example, in shale gas where ample time for swelling is available prior to the frac campaign, money can be saved by running the water swellable elastomers to match the low cost water based drilling fluid, thereby saving costly displacements to diesel/mineral oil.

Tendeka offer swellable packers for both oil and water with a pressure rating in excess of 10,000 psi (680 ATM).

Packers:

What are the key differences for operators if selecting either an inflatable or swellable packer?

Baker Hughes: Swellable packers are a more cost-effective technology with less operational complexity than inflatable packers. However, inflatable packers have a larger operational envelope when considering irregular and washed out hole geometries. Additionally, cement inflated packers can be used at higher temperatures than most swellable packers. Another advantage of the inflatable packer is that it has a large expansion ratio maximizing run-in clearance.

The swellable packer is a short joint of casing that is wrapped with an elastomer that swells when exposed to oil or water creating a seal. An advantage of the swellable is that no pressure is required or pipe manipulation to set the packer making installation very simple and straight forward.

Inflatable packers could be described as “active packers” that can be set through pump pressures from surface. These packers can be set immediately and there is no time delay waiting for the elastomers to swell to make a seal. Swellable packers could be considered more “passive” in that no action would be required from surface to activate the packer. Both systems may have application depending on specific well conditions.

Halliburton: Inflatable packers are activated by the application of pressure down the tubing string which packs the packer off to achieve the desired seal. The overall seal lengths are usually fixed and one packer size is capable of setting in a range of openhole sizes. Swellable packers are activated by the presence of a swelling fluid and will conform to the openhole section. They can be designed to cater the well conditions by varying the length and OD of the elastomer to achieve the required ratings for a specific well.

Packers Plus: I touched on this in a previous answer about designing for the application, but in my opinion swellables were originally developed for low pressure differential, constant temperature environments where setting time is not critical. The majority of wells in Russia, like in North America/Canada, require stimulation. Testing has shown that the rapid cooling during fracture stimulation (due to pumping fracture fluid from surface), while maximum pressure being applied can cause the swellable to contract to a point where its sealing capability is compromised. In a technical paper written on the subject it was stated that “The contraction will lead to a drop in internal element pressure; ultimately, it will result in a physical shrinkage, and the pressure seal will be lost” (Evers et al., 2009 – OTC 20159). Because of this, mechanical packers are the most commonly used type of packer in stimulation applications.

Another factor is time. At best, it can take a week for the swellable packers to fully activate (set). This is one week longer than the process required for setting mechanical packers, and therefore one week less production. A week is not a long time for a single well, but when multiplied by the thousands of wells drilled, completed and stimulated in Russia, it adds up to a lot of lost production. With a mechanical packer there is no need to wait as they are set hydraulically immediately after the system is installed.

TAM International: It greatly depends on the application, if the packer is going to be used in an application where instantaneous isolation is required as in stage cementing, air drilled hole applications, lost circulation zone isolation, preventing gas cut cement, or critical zonal isolation with cement then the inflatable packer is the tool of choice.

If there are large temperature changes or high pressures projected or if you are performing open hole completions requiring zonal isolation, multi-lateral junction seals, secondary liner top seals, preventing micro annulus on cementing operations then a swellable packer would be the preferred tool.

Both the inflatable packer and swellable packer can be used in many similar applications, but both have their limits as well. The swellable packer is lower risk in damaged casing; if the rubber is cut during run in, it is self healing. If the inflatable packer is cut during run in, it cannot be inflated. When using the inflatable packer you get a pressure response indicating the packer has inflated and is isolating; you do not have this indication with swellables. Swellables typically take days to swell and provide pressure barriers; with inflatables there is no down time waiting for isolation.

Tendeka: Inflatable packers have an hydraulic activation mechanism metering fluid into an inflatable bladder. Once a certain pressure has been achieved, the valving mechanism will close and trap the inflation fluid inside the bladder. As such, inflatable packers are very useful where instant isolation is required, during stage cementing for example. Applications requiring a large expansion, greater than 2 inches. A smaller run in diameter also favours an inflatable packer over swell packers.

Swellable packers do not require hydraulic pressure to activate the packer, which simplifies the installation process.  The simplicity of the system saves rig time and the risk of running small diameter inner strings and complicated pressure actuation systems. The lack of valve systems and potential leak paths also makes swell packers a more robust long term solution for cement integrity and production applications.

It can therefore be argued that inflatable packers have found a niche in stage cementing and large expansion applications. These include thru tubing bridge plugs, in which swellables will not be able to compete, in the same way that swellables have made a huge impact in payzone isolation due to the simplicity and long term isolation assurance.

Hybrid swellable and mechanical/inflatable systems are entering the marketplace to aid in high expansion and retain the fluid within the bladder. When an swelling medium is not present such as a Gas well. These hybrid packers (swellable material inside the bladder) provide a “best-of-both-worlds” solution. However, large running diameters and high cost will most likely limit its popularity.

Considering the well environment, how does packer selection aid the completion process?

Baker Hughes: Both swellable and inflatable packers have increased the viability of the un-cemented open hole completion. This technique eliminates the costs of cementing and perforating, and limits the potential production loss due to skin damage caused by a cement job. Additionally, either technology can be used as positive points of isolation in un-cemented completions to control unwanted production at a later date.

Well environment has a large effect on the selection of the production packer including pressure, temperature, annulus completion fluid, produced fluids (corrosive environments) and production rates. The well environment will dictate the metallurgy and seal (elastomeric) element. Permanent packers are typically used on a high performance (i.e. high pressure/temperature) wells and these are set on wireline/hydraulic setting tool or by applied hydraulic pressure. Permanent packers are removed by milling it. Retrievable packers generally are associated with lower pressure wells and set by wireline, hydraulic pressure or tubing manipulation. These are generally removed by tubing manipulation. However today’s retrievable or removable packers have almost equal performance than permanents. The right selection of the packer will save time and expenses over the life of the well and can prevent expensive workovers later. Some of the major considerations when selecting a packer include the type of well (new, re-complete, gas, oil, artificial lift, injection, single, dual, horizontal, multilateral, etc.) and also future well treatments (stimulation, acidizing, etc.).

A properly installed packer (or packers) provides the completion engineer with more assurance the completion fluids being used will be directed to the desired location in the well. The packers allow positive isolation of various zones within the wellbore, and can reduce the risk of communication of the fluids to other areas within the wellbore.

Halliburton: Packers are used to provide zonal isolation either in open or cased holes. This is crucial to providing a safe and effective means of producing a well and because of this is a very important part of the completion process. Understanding the capabilities of packers, the necessary setting process, and how this plays into the entire completion program will ensure that the proper packer is selected for the completion.

Packers Plus: Packer selection is a key factor in determining whether you make it to bottom or not. For example, a swellable packer is typically much longer than a mechanical packer (10-30ft versus 5ft). Multistage fracturing by its nature requires multiple packers. At present, customers in Russia are doing about 5 stages (so 5-6 packers), but it will not be long before they are doing 10, 15 and most likely much more as that is the way the North American/Canadian market has gone. We have installed 47 packers in one open hole wellbore and will soon be doing many more. With drag and dogleg severity (DLS) to contend with, higher numbers of stages simply are not feasible with swellable packers. If the completion gets stuck, either differentially or mechanically, then there is a high risk of preswelling, which would required the completion to be pulled if the rig was able to overcome the drag of the packers. Preswelling and non-swelling is not uncommon. We have installed a number of completions in wells that were originally completed with swellables and failed.

TAM International: The packer selection is based on what is to be achieved over the life of the well. Pressure, temperature and corrosive fluid requirements are critical to the selection of the correct packer. Packer selection should also minimize the risk involved while providing the best solution for the customer, both short-term and long-term.

Tendeka: When instant setting is required, swellable packers are excluded. This might also be the case in extreme environments as high temp / high pressure gas wells and super shallow artic wells.

Optimum packer selection is often based on the number of isolation points required. As the number increases, the installation complexity of inflatable packers might make the risk and cost too high, and swellable packers provides the added benefit of simplicity in the deployment and installation.

What are the key advantages of the various types of packers?

Baker Hughes: Swellable packers offer the most operationally efficient solution to annular isolation; however, wellbore fluid composition and required swell % must be carefully considered when designing a swellable solution. Inflatable packers have the capability to expand significantly further than swellable or mechanical packers, but require an added degree of operational complexity. Mechanical packers are a viable alternative to swellable or inflatable packers in that they are not as sensitive to wellbore conditions like temperature and fluids, and can be set in a variety of ways such as hydraulically or mechanically with an inner string.

Permanent packers are typically the most reliable option for extreme and hostile conditions. However, removal of permanents involves milling operations. In general permanents offer simplicity and less moving parts. Since permanents do not have a retrieval mechanism, these have a larger internal diameter and better performance (pressure and load) envelopes than retrievable packers.

The retrievable option offers flexibility and lower cost especially when the removal is anticipated in the short term, or repeatedly in the life of the well. In general the ability to retrieve is at the expense of lower performance envelope (differential pressure and load ratings) and reliability. However, these have improved dramatically in recent years. Some of the current retrievable designs actually rival permanent packer performance in some size ranges. Despite performance enhancements, retrievable packer models can still dictate limitations in their internal diameter specifications, associated with the internal bypass and retrieval mechanisms.

Mechanically activated packers, like inflatable packers, give a positive indication that the packer has been activated by evaluating the pressures and volumes used during setting of the packer(s). As noted, there is no need to wait for the packer to swell, and the packer can be designed to work in any fluid environment equally well. These packers however do require activation from surface, and may require additional rig time for the activation, depending on their design. Swellable packers do not require actions from surface, thus potentially saving on rig time. Additionally, the swellable packer can also be used for situations where later in the life of the operation, wellbore fluids migrate to other areas of the well because of seal failures elsewhere in the well. These can be brought on by changes in wellbore stresses resulting in loss of seal integrity from cement or other materials in the well.

Halliburton: Permanent packers typically have a simple design that can be set on wireline, slickline, coiled tubing, or jointed pipe and can only be removed from a well by milling. Retrievable packers come in a range of designs that vary the setting method (wireline, mechanical, hydraulic, and hydrostatic). These can be retrieved from the well and typically are a more complicated design. Swellpacker systems are a very simply designed packer that will swell in the presence of a fluid and will conform to the environment that it is set in.

Packers Plus: The advantages of mechanical packers in stimulation applications has been outlined in previous answers. For lower pressure differential screen applications where there is no tubing integrity, swellables can be a good fit as they can be run in and left to swell assuming the well conditions, primarily temperature, are right. It should be noted though, that it is still possible to do the same application with mechanical packers if an inner string is used for setting them. We have performed such operations on a number of occasions in South America.

There are other packer types such as inflatable and metal sealing, but these have minimal installation history and customers typically only talk in terms of mechanical and swellable.

Mechanical packers will always be more robust in terms of performance than swellables, but depending on the application, one may be more suitable than the other. This goes for any piece of equipment that gets installed down a well.

TAM International: You can write a small book on this. If large anchoring forces are required, then a mechanical packer is the only option. If there are restrictions that the packer must pass through, then an inflatable packer is the way to go. If there are no restrictions and no anchoring required, swellable packers are the answer. The following is a more detailed comparison of inflatable and swellable packers.

Inflatable Packer:  
»    Provide a high or low pressure seal to either the casing or formation depending on the parameters of the well construction or formation.
»    Provide an instantaneous seal for supporting a cement column
»    Provide an instantaneous seal for isolating gas, to prevent gas cut cement.
»    Provides a barrier to prevent gas channelling behind the cement and casing, and micro annulus between casing and cement.
»    Conforms to irregular shaped bore holes.

Swellable Packers:
»    Provide seal lengths from 1ft – 20ft (standard) and custom lengths.
»    Low risk involved in installation.
»    Offered in oil, water, or a combination of both swellable elastomers.
»    200% usable volume expansion.
»    Offered with Smart/Intelligent feed thru capability.
»    Conforms to irregular shaped bore holes.

Tendeka: Short slip-on style swell packers
»    Cost effective and a high number of isolation points in long horizontal wells
»    Allows for use of customer pipe – reducing cost
»    Long term sealing integrity

Long pipe mounted swell packers
»    High pressure differential
»    Shale gas – multi-zone frac
»    Long term sealing integrity

Conventional inflatable packers (external casing packers)
»    Stage cementing
»    High expansion ratio
»    Inert during installation

Thru-tubing inflates
»    Ultra high expansion ratio
»    Sometimes only option available

Plugs:

What applications are your plugs designed for?

Baker Hughes: Baker Hughes offers a variety of different plugs that provide flow and well control such as well suspension, barrier, blanking plugs, check valves and bridge plugs. Our plugs are also for testing production tubing string and setting hydraulic set packers.

Baker Hughes also offers a full range of bridge plugs that manufactured from high strength composite materials that makes the drill out and removal from the wellbore much faster and efficient. These types of bridge plugs are often utilized to enable multiple stage fracturing operations in a single wellbore. They provide a high pressure barrier between each of the perforation intervals and multiple plugs can be easily removed from the wellbore through a single milling operation.

Halliburton: Bridge / Frac Plugs are designed to either provide short or long term isolation in a well. They are set a variety of ways in a variety of casing sizes and can be permanent, retrievable, or drillable. The most common application for plugs is in cementing and fracturing operations.

TAM International: TAM plugs can be used in every aspect in the life of the well for both open hole or cased hole applications, as well as temporary or permanent applications. They can be deployed by slick-line, wireline, coil tubing or work string.

What are the most commonly run plugs in Russia and what is the most common means for setting?

Baker Hughes: A variety of different plugs are currently being used in Russia to accommodate various applications. Slick line deployed plugs are set into seating nipples to provide flow control and pressure testing operations while many tubing and drill pipe deployed bridge plugs are being utilized for both permanent and temporary well abandonments.

Halliburton: The most commonly run plugs in Russia are the drillable product lines and are usually set using a mechanical setting tool run on tubing.

TAM International: Inflatable bridge plugs that TAM provides are our 425-SS-01 Single Set Bridge Plug with a slat style element. It is used to run thru casing restrictions, set in the casing to isolate water production from below.

How do you activate and remove your plug?

Baker Hughes: These can be deployed and removed via wireline. The plugs is typically connected to a lock mandrel which lands and sets in a nipple profile in the completion string. This can also be deployed/removed with an overshot and land in a packer. Plugs can also be set anywhere in the tubing by using a packer/plug combination (i.e. No profile required plugs, etc.) which is deployed with electric line, slick line or coil tubing and retrieved on slick line.

Halliburton: Bridge Plugs are designed for retrievable, permanent, and drillable applications. The plugs can be set by any method currently used by industry (wireline, slickline, coiled tubing, mechanically, hydraulically), and can be removed from the well any of the industry accepted methods.

TAM International: Typically our plugs are run on a work string or coil tubing. Our bridge plugs are pressure actuated by pumping a ball down to the tool, which seats in a choke and allows the pressure to be increased to a pre-determined pressure setting. Once the inflation pressure is achieved, the set sleeve shears and locks the pressure into the element. At this point, the pressure can be increased and the work string hydraulically disconnected (by rotation or straight pull) from the bridge plug. An optional mechanical release On/Off tool can be used to release from the bridge plug. For temporary bridge plugs, once the purpose of the operation is achieved, a retrieval mechanism can be run to unset the bridge plug and remove it out of hole. TAM also has wireline setting capability if required.

Centralizers:

Looking at the tragic accident in the Gulf of Mexico, centralizers were highlighted as a key device to aid in ensuring a proper cement bond. How is this achieved?

Baker Hughes: Centralization is obtained through the proper selection and use of centralizers on the casing string. The centralizers are specifically designed for particular pipe and hole size configurations to provide stand off from the formation, thus allowing proper cement placement. There are several types of centralizers available for different applications, from bow spring to rigid, solid centralizers.

Centek: Choosing centralizers should not be a trade-off between costs and well safety. It is vital to use the right number of good quality and reliable centralizers. The most important aspect of centralization is to choose the best equipment for the intended application. Smaller, undersized to bore hole units, allow irregular fluid flow paths to occur. Oversized centralizers simply create drag issues from the first unit down the hole. Gauge units create the optimum solution as they enhance both RIH and stand-off. The key aspect to a superior cement job is stand-off. Stand-off dictates fluid regimes; cement isolation, drag concerns and rotational forces. Units must be flexible to absorb the down hole forces applied to casing/tubing so that bridging is minimized yet stand-off is retained. Good well clean out is essential to good bonding, again, if the pipe lies on the low side this will not be achieved.

In what applications should centralizers be utilized?

Baker Hughes: Centralization is essential where a wellbore seal is required. Without proper centralization, cement cannot be circulated completely around the casing, and the potential of leaving a mud channel, and thus a flow path, is increased. The degree of centralization will depend on wellbore configuration and should be individually designed for each well.

Centek: In line with oil industry guidelines and Russia’s GOST requirements, centralizers should be used in every section of the well and whenever casing, tubing, and completions are run. A centralizer should be used in all well types, as pipe will always lie on the bore wall even in a vertical well. Horizontal applications are critical, as here the pipe has to be pushed into the well. Lack of centralizers in this case means the tubular goods would create a high resistance to movement which centralizers will dramatically reduce. The likelihood of bridging is increased and the cement job will be compromised as the fluid will take the easiest route. Solid type units, whose stand-off is already impaired, also create this effect. Oversized units in the horizontal create too much drag and damage easily. Applications, for all well designs, require a good understanding of centralizers to achieve the desired end result.

What are the main benefits of centralizers?

Baker Hughes: Centralizers serve to keep the casing away from the formation wall and move the casing to the center of the wellbore, allowing for improved placement of the cement sheath. Care must be exercised in the selection of the type and location of the centralizers to assure the casing is properly centered in the well, while allowing the casing string to be lowered into the well. Sophisticated models are available to predict centralization in the well as well as the forces exerted by the centralizers while the casing is being lowered into the well.

Centek: A centralizer is an aid to getting tubular goods or completion systems to the desired position in the well. They act as a bearing, and the main objectives are to keep the pipe off the bore wall at all times. Gauge units achieve the best results for any well application. Centralizers are also designed to ensure good well cleanout, but, most importantly, to ensure good zonal isolation and to bond to the formation. They should not be oversized as this creates drag nor should they be undersized as this reduces the stand-off ratios. Centralizers need to absorb mainly lateral loads caused by inclination and azimuth well changes. Robust and high restoring force units are far superior as they also allow for flexibility in the well. Units should also be strong enough so as not to break or be damaged should casings have to be pulled out of the well.

Sand Control:

What are the most common types of sand control used in Russia?

Baker Hughes: Most wells in Russia have very limited sand control provision incorporated into the well design and this can lead to premature completion failure or reduced pump run life. Many wells in Russia have been completed with a slotted liner or a stand-alone screen assembly, and while both are very economical techniques, they typical do not provide adequate sand control for an extended period of time. We are now seeing more operators explore the benefits of gravel packing techniques and how it can provide a longer term sand control solution for their projects. Baker Hughes has recently been awarded an offshore project in Russia where we will be providing gravel pack equipment and services.

Halliburton: Currently companies are running slotted liners in an attempt to prevent sand influx during the production. There is also an increased interest in screens that can be run to help in preventing sand production.

Tendeka: The most common types of sand control depends on the well types; i.e horizontal, deviated or vertical wells. With the increased popularity of horizontal wells, simple slotted liner deployments have gained a lot of popularity. The simplicity of landing a slotted liner into a horizontal wellbore seems like a very good option for a low cost solution to prevent the bore hole collapsing, but this carries inherent risks associated with corrosion, lack of lateral isolation and the inherent onset of water production causing loss of sand control. Higher end solutions, such as open hole gravel packing, premium sand screens, inflow control screens, and compartmentalization are improvements over the traditional “slotted liner” methods.

Frac-packing and expandable screen solutions are also deployed in more conventional wells in a smaller scale due to their inherent cost and infrastructure requirements.

What problems can a loss of sand control cause to the well, equipment and to production?

Baker Hughes: The lack of adequate sand control in a well can lead to many problems throughout the well life. The accumulation in surface equipment is common if the production velocity is great enough to carry sand up the tubing, the sand may become trapped in the separator, heater treater, or production pipeline resulting in the need to shut-in the well and clean out.

Sand can also accumulation downhole if the production velocity is not great enough to carry sand to the surface, the sand may bridge off in the tubing or fall and begin to fill the inside of the casing. Eventually, the producing interval may be completely covered with sand. In either case, the production rate will decline until the well becomes “sanded up” and production ceases resulting in the need for remedial operations.

The loss of sand control in a well can also result in the erosion of downhole and surface equipment in highly productive wells where fluids flowing at a high velocity and carrying sand can produce excessive erosion of both downhole and surface equipment leading to frequent maintenance to replace the damaged equipment. For some equipment failures, a rig assisted workover may be required to repair the damage.

The lack of sand control can also cause the collapse of the formation resulting in large volumes of sand to be carried out of the formation with produced fluid. If the rate of sand production is great enough and continues for a sufficient period of time, an empty area or void will develop behind the casing that will continue to grow larger as more sand is produced. When the void becomes large enough, the overlying shale or formation sand above the void may collapse into the void due to a lack of material to provide support. When this collapse occurs, the sand grains rearrange themselves to create a lower permeability than originally existed. In most cases, continued long term production of formation sand will usually decrease the well’s productivity and ultimate recovery. The collapse of the formation is particularly important if the formation material fills or partially fills the perforation tunnels. Even a small amount of formation material filling the perforation tunnels will lead to a significant increase in pressure drop across the formation near the well bore for a given flow rate.

Halliburton: In reservoirs where sand influx is an issue, it is necessary to control the sand down hole to prevent damage to the completion and surface equipment used. If this is not performed properly, sand will enter the well and cause problems with the equipment’s functionality and possibly eliminate production all together. The production rate will determine how fast the sand enters the well and the time to failure. The extent of damage can be as serious as erosion of equipment to failure (and possibly uncontrolled release) or as limited to sand building up down hole preventing production.

Tendeka: Loss of sand control is not necessarily a catastrophic event depending on the tubulars and surface equipment’s ability to handle the produced sand. In heavy oil, producing sand is sometimes associated with an increase in productivity and may be a positive artefact. However, in conventional wells, sand production can cause failure of artificial lift equipment such as electric submersible pump’s (ESP’s). Surface equipment erosion in gas wells may prove an operational hazard and in oil wells, sloughing of sand into the wellbore can cause complete loss of production from the lower zones. In horizontal wells, sand production may not be seen on the surface due to the duning of the sand, but a total loss of production or limited production may be a common outcome. In general, it is always better to limit any form of sand production than allowing for unconstrained production, hence the term sand control.

There are a wide range of sand control solutions available. How do you select the best available option?

Baker Hughes: Numerous techniques are available for dealing with sand production from wells. These range from simple changes in operating practices to gravel packing/frac packing. The sand control method selected depends on site specific conditions, operating practices and economic considerations. Baker Hughes provides the full portfolio of sand exclusion techniques including stand-alone screens with and without Inflow Control Devices (Equalizer), gravel and frac packing (including associated pressure pumping services), oriented perforating, expandable screens and more recently, GeoFORM Shaped Memory Polymer System. To select the most appropriate technique for any application it is important to thoroughly review each of these options with a Baker Hughes Sand Control representative.

Halliburton: Depending on the economics of a well, a viable solution can be selected depending upon the formation properties and the completion requirements for the well. Gravel pack completions and screens are solutions that have been employed globally with great success but can be a more costly solution due to the engineering and equipment that is required. The best approach for determining the proper technology is to discuss the well parameters and anticipated production with the service provider.

Tendeka: Typically, each reservoir and field development requires a unique approach to the sand control solution. For some fields, saving CapEx by operating wells below the sand free rate might be optimum, while in other fields there is no option but an initial sand control deployment. In cases where sand control is required initially, well positioning, cased versus open hole and required production rates are first and foremost in the field development plan. Following these decisions, a sand control solution can usually be devised. In summary, some examples of optimum sand control could be:
»    Multi zone frac-packing in cased hole (high rate wells in cased hole)
»    Horizontal inflow control screens with swellable packers (single horizon reservoirs)
»    Open hole horizontal gravel packing (shaly resevoirs)
»    Open hole vertical gravel packs (high rate gas wells)

Well bore clean out:

Why does well bore clean out aid a wells completion?

Baker Hughes: Wellbore Cleanout is the utilization of specially designed tools, chemicals and techniques necessary for removal of the debris from the wellbore that interfere with normal operations during the life of that well.

Wellbore cleaning operation cleans casing, tubing, BOP or riser ID, removes any debris at downhole or suspended in the wellbore, and assists fluid exchange.

Wellbore Cleanout provides insurance for completion and workover, reduces nonproductive time, and manages risks during completion installation and workover activity. In additional, it minimizes damage to reservoir and delayed production. The historic data have showed that more than 30% of non-productive time is linked to debris issues in the wellbore. According to the recent Welling Report, “Debris management in completions operation is a major concern for approximately 1/3rd of the operators surveyed and a minor concern for an additional 1/3rd of the operators.”

Halliburton: Wellbore preparation helps in ensuring that any debris or scale that may be in the well prior to running a completion is effectively removed. Completions will require the ability to manipulate tubing (for functioning of mechanical components) or apply hydraulic pressures in order to set or shift components. The presence of any scale, debris, or foreign objects can prevent this from happening and could potentially result in a costly work over. Application of wellbore cleanout tools will provide an “ideal” environment for running a completion.

How is this utilized in Russia?

Baker Hughes: Currently, the wellbore cleanout has been mainly used in Russia at the workover stage to clean the casing ID, remove downhole debris, and support fishing or casing exit works. The wellbore cleanout is also used at pre-completion stage to clean the wellbore and assist the fluid displacement.

The common wellbore cleanout tools used in Russia include casing scraper, casing brush, wellbore filter, downhole magnet, boot basket, VACS tool and circulation tools.

What advantages and savings do your wellbore clean out solutions bring?

Baker Hughes: Baker Hughes provides complete wellbore cleanup portfolio and services for all applications from low cost land to high end deep and ultra-deep water applications.

The Baker Hughes X-Treme Clean™ wellbore cleanup tools features non-rotating technology efficiently cleaning while minimizing potential damage to the casing or riser ID, high allowable rotational speed with a large total flow area offering more effective well cleaning and displacement. We have more than 2,500 jobs worldwide.

The BHI vectored annular cleaning system (VACS™) is leading in the industry effectively recovers debris at downhole in openhole or cased hole. The benefits include keeping debris from reaching to the surface equipment or suspended in the fluids, protecting debris sensitive equipment, minimizing impact to perforation and formation, and easy adapting to a variety of applications. It can be used in conjunction with other tools to perform wellbore cleaning and other operations such as packer retrieving in one trip, It is especial useful in the applications such as wells with low fluid level, wells with partial or total lost circulation, deep or deviated wells.

Lukasz Ostrowski: Baker Hughes
Lukasz Ostrowski is currently Baker Hughes Completion and Reservoir Development Services Marketing Director for Russia and CIS Region, located in Moscow. He holds a PhD in Petroleum Engineering from the University of Mining and Metallurgy – Krakow, Poland (1984). He began his career at the same university, afterward joining Preussag Oil & Gas AG as a gas-reservoir engineer in Hanover, Germany (1986). From 1987 to 1997, Ostrowski went on to work as a consultant then Managing Director for Golder Associates in several countries across Europe. In 1997, he joined Baker Hughes as a Manager for Testing Services – Eastern Hemisphere, relocating to Russia in 2003. Since 2006 Ostrowski has been teaching as an Honorary Professor of Technical University Clausthal (Germany). In 2009, he was named a Visiting Professor at the University of Mining and Metallurgy in Krakow. Ostrowski has authored more than 35 papers on reservoir engineering and completions for the Society of Petroleum Engineers and other publications.

Ryan Mattson: Halliburton
Ryan Mattson is a Technical Advisor with Halliburton International, Inc.  Ryan is currently based in Moscow and has been working with Halliburton for six years.  Prior to coming to Russia, Ryan was based in Canada focusing on cased and openhole completions in North American markets, with a primary focus on horizontal openhole completions.  Ryan graduated from the University of Alberta in Edmonton, Alberta, Canada with a BSc in Mechanical Engineering.

Paul Higginson: Packers Plus
Paul has 14 years experience in the oil and gas industry, having begun his career in the design office of Petroleum Engineering Services Ltd working with Completions, Intervention and Intelligent Wells equipment. He has worked internationally in Europe, Africa, Asia and the Middle East in operational, project engineering and sales roles in the field of Intelligent Completions where he was exposed to a multitude of different technical environments. For the last 2-1/2 years he has been the focal point for Packers Plus in Europe and Russia focusing on Open Hole Multi Stage Fracturing Completion solutions.

Boris Lomakin: Tenaris
Boris Lomakin is part of Tenaris’s Technical Sales team in Russia. He has a degree in Petroleum Engineering and Technical Interpretation from the Samara State Technical University. He has been with Tenaris for three and a half years. Mr. Lomakin is a Russian citizen.

Dr. Sergey A. Rekin: ТМК-Premium Services
Dr. Sergey A. Rekin is the General Director of ТМК-Premium Services. He is also a API and ISO (Russia) committee member, Chairman of the Subcommittee No.7 of the Technical Committee 357 GOST & author of 70 publications, 3 monographs and 7 inventions. Having been educated at the Sverdlovsk Suvorov Military School and the Kuibyshev Polytechnic Institute Dr Rekin joined Gazprom VNIIGAZ in 1999, and TMK in 2006. He currently works for the Premium Services division of TMK.

Cliff Berry: Centek
Cliff Berry’s oilfield career started in 1977 with Halliburton in Brunei, Malaysia and Sarawak as a cementer and tool operator. He also worked offshore in the North Sea and Persian Gulf with Halliburton, leaving Halliburton as an MSO. He then worked for Diamond B (UK) Limited, a leading centraliser manufacturer in the mid 1980’s. Cliff joined BJ Tubular Services as European Operations Manager working from the German office and successfully introduced BJ Tubular Services into Denmark, Hungary, and Holland in addition to growth in Germany. He joined Centek in 2001 as Sales and Marketing Manager responsible for worldwide sales..

John Stewart: TAM International  
John Stewart began his career with Baker Production Services in Aberdeen in November 1982 as a trainee Well Test Engineer before transferring to Great Yarmouth in January 1983. John worked in the North Sea, Europe and Africa gaining experience of all types of wells and rig operations and progressed to Senior Well Test Engineer by the time he left Baker in 1985. John then joined Petrocon Production Services where he gained experience in wireline operations, cased hole and open hole DST operations onshore in the UK, Tunisia and the Southern North Sea. He progressed to the position of Operations Manager during which time the company was acquired by ERC and Simon Engineering. He joined Tam International in Aberdeen in 1994 as a Sales Engineer. John has been with Tam for over 17 years and is now the Sales Manager in the Aberdeen office, overseeing the sales for Europe, Africa, The Middle East, Russia and the former Soviet Union.

Malcolm Pitman: Tendekal  
Malcolm Pitman, Vice President Europe, SSA and FSU has worked in the oilfield industry for over 30 years. Prior to joining Tendeka in 2008, Malcolm held a number of positions within Baker Hughes, Zeroth Technology, Baker Oil Tools and BHI Corporate where he was responsible for business development, supply chain management, manufacturing, engineering, financial reporting; as well as overall management of the Well Intervention function of BOT UK. He brings an extensive knowledge to Tendeka specializing in well construction, well intervention, new technology and mature field development. Malcolm holds an MBA from Robert Gordon University.