PDVSA Optimizes Surface Well Testing Operations with Fit-For-Purpose Mobile Production Testing Units

Operator deploys compact units to increase efficiency of dynamic well cleanup campaign, onshore Venezuela

Challenge: Obtain accurate and reliable production testing measurements during cleanup operations, in a timely manner, from more than 120 oil wells onshore Venezuela.

Solution:

• Deploy Schlumberger mobile production testing technologies and personnel, including a fit-for-purpose trailer-mounted surface well testing unit containing a separator, choke manifold, and emergency shutdown (ESD) system ideal for the dynamic operation.
• Integrate with Schlumberger CT technologies and services to consolidate resources and minimize third-party rental accessory costs.

Result:

• Increased production testing efficiency and reduced footprint by employing robust modular technologies.
• Enhanced operational safety with fit-forpurpose equipment designed to the highest safety standards.
• Enabled rapid response times for project execution.

High-volume well cleanup campaign necessitates efficiency

For a campaign of more than 120 oil wells in the Furial and Punta de Mata fields of eastern Venezuela, PDVSA sought a compact production testing solution that would save space at the wellsite during the well cleanup phase. A package of standardized technologies and services would help optimize cleanup and surface well testing activities on such a vast spread of wells. With technologies and a standard operating procedure best suited for the environment, PDVSA could apply the same operational efficiency to multiple wells in the region with equipment and personnel committed specifically to its projects.

Standard operating procedure eases transition between multiple wellsites

The lean design of Schlumberger mobile production testing units enabled PDVSA to successfully test a greater number of wells per day, while maintaining a reduced wellsite footprint. A smaller manifold and separator were both introduced with no negative affect on the operating parameter envelope. The ease of transporting the mobile units enabled PDVSA to rapidly transport dedicated technologies and personnel from one wellsite to another.

Mobile production testing units integrate seamlessly with wellsite operations

To effectively obtain measurements during cleanup from wellsites with limited space, PDVSA worked with Schlumberger to select efficient, fit-for-purpose mobile production testing units to meet surface well testing objectives. The modular mobile units were outfitted specifically for PDVSA's operations and ensured the availability of technologies and experienced personnel best suited for the multiwell project. With a large number of wells requiring testing across the region, the mobile production testing units offer PDVSA operating efficiency beyond that of traditional nonmobile options.

The design of the mobile units took into consideration Venezuelan restrictions on imports and equipment on wheels without sacrificing efficiency. An onboard separator handles both high and low gas flow rates, while a 10,000-psi choke manifold and ESD system help ensure proper well control. With an agreed-upon design Schlumberger can rapidly mobilize additional units and spare parts to supply the high volume of PDVSA activity. And, with other Schlumberger resources readily available, CT or wireline operations can be easily integrated with existing surface well testing operations.

Download: PDVSA Optimizes Surface Well Testing Operations with Fit-For-Purpose Mobile Production Testing Units (1.55 MB PDF)

Case Study: Innovative Completion Design and Job Execution Result in 100% Gravel Pack in 136° Fishhook Well

Operator overcomes challenges posed by shallow offshore well with steep trajectory drilled from onshore

Challenge: Find an efficient way to develop offshore hydrocarbon prospects and control sand production in shallow-water fishhook well from onshore drilling location.

Solution: Design a gravel-pack system specially suited for wells with fishhook trajectories with the following technologies:

• OptiPac Alternate Path openhole gravel-pack screen
• Hornet skid-mounted gravel-pack blender
• ClearPAC polymer-free gravel-pack fluid
• fast-acting oil-swellable packers
• pressure-activated diverter valves
• antiswab washdown service tool.

Result: Achieved a full annular gravel pack in the inverted-angle well with zero sand production; successfully met production and injection targets.

Fishhook trajectory poses specific challenges for sand control completion

An operator was developing a field along the coastline offshore Southeast Asia. Targeting this marginal oil required drilling into multiple hydrocarbon prospects with stacked shale and water zones. Drilling the wells from offshore was deemed uneconomical. Accessing the oil from land wells that tied into existing onshore infrastructure would be more efficient and allow immediate production.

The company planned an openhole "fishhook" well with an upward trajectory of up to 136°. The openhole interval was to be more than 700 m long and have six zones. Gravel packing had to be accomplished at the steep angle without exceeding the fracture pressure. The upward trajectory would make it difficult to keep the proppant from sliding and bridging in the wellbore, which would prevent a full annular pack.

Innovative gravel-pack design minimizes friction pressure, ensures full gravel pack

To mitigate the bridging and promote heel-to-toe packing, Schlumberger recommended an innovative gravel-packing system that would minimize friction pressure during the operation and help ensure a full annular gravel pack in the challenging environment.

A screen completion string, designed to accommodate six zones, included five oil-swellable packers to isolate the zones in the openhole interval. A sixth oil-swellable packer was placed inside the casing above the top of the screen to provide a bottom for the pack and to encourage heel-to-toe packing from inside the casing shoe. These fast-acting swellable packers were soaked in a diesel oil that allowed the elastomer to swell against the openhole rock before the zones were gravel packed, isolating the zones and preventing the pack from sliding downhill during gravel packing.

Pressure-activated diverter valves incorporated into the internal service string were evenly spaced along the openhole section to minimize the circulating pressure exerted on the formation during the packing operation. These valves short-circuited the washpipe at various locations, shortening the length of the washpipe through which the returning gravel-pack carrier fluid had to travel.

The system included the OptiPac Alternate Path openhole gravel-pack screen, which has shunt tubes to prevent bridging. The shunts diverted slurry accumulations into the zones between the packers until the annulus was fully packed. Transport and packing tubes delivered slurry to the area between the screens and the wellbore. This design reduced slurry dehydration inside the shunts, eliminating the risk of bridging into the tubes and extending the potential length of the gravel-pack interval.

The Hornet skid-mounted gravel-pack blender was used to optimize delivery. The ClearPAC fluid was chosen as the optimal gravel carrier fluid because of its capabilities to reduce friction and suspend the gravel at low shear rates. The viscoelastic gel also helped control leakoff through the nozzles of the packing tubes.

The antiswab washdown service tool stabilized the hydrostatic pressure in the open hole, eliminating the swabbing effects of hardware movement and ensuring filtercake integrity before gravel placement. After the excess gravel was screened out and reversed, the service tool allowed spotting of filtercake removal treatments, eliminating a dedicated cleanup run.

Completion design and job execution ensure 100% gravel pack

The combination of technologies resulted in a 100% gravel pack below the fracture pressure of the well. Accessing the well from an onshore location enabled the operator to reduce the costs and risks related to offshore operations. As a result of this success, 10 additional fishhook wells, both injectors and producers, were completed along the shore. This new completion design provides an alternative method for gravel packing fishhook wells with narrow frac/pore-pressure windows and developing hydrocarbon prospects in shallow waters from onshore drilling locations.

Download: Innovative Completion Design and Job Execution Result in 100% Gravel Pack in 136° Fishhook Well (0.27 MB PDF)

Related services and products

	Openhole Sand Control Services
	Sand Control Pumping Equipment
	ClearPAC Polymer-Free Fluid for Gravel Packs

Suspension trauma - harness hang syndrome (HHS)

How long can an individual stay in a static vertical suspension e.g. after a fall arrest has occurred?

Your question seems to be about HHS or Suspension Trauma.

This is an important post-fall risk and many in oil industry are not aware of it so this is a good question to ask to let many more aware of it.

One should read the research on it to completely understand this part. On internet it is available at http://www.hse.gov.uk/research/crr_pdf/2002/crr02451.pdf

An human can faint and die if left hanging because of less supply of oxygen to his brain.

As per research the person hanging from harness will feel Harness Hang Syndrome even after "few minutes" depending on person's pre fall state (diet, health etc.)

1. But I guess the oil and gas checklist requires that person should be rescued in less than 15 minutes.

Checklist: "How will rescue be assured within 15 minutes of the occurrence of a fall to minimize the risk of further injury or death due to suspension trauma?"

2. Experiments have shown that people can start loosing consciousness in less than 10 minutes. 

"So what are the symptoms of HHS? The FFS testing showed that HHS symptoms
appeared in no more than 10 minutes with healthy subjects. Brinkley's research showed
that 6 minutes was the normal onset time."

3. The research done has showed that person hanging from a harness can start feeling HHS even in 3 minutes. 

Further emphasizing risks of suspension phase - 

"The fall and the arrest of it are only part of the story, and not necessarily the most dangerous. After the fall and its arrest comes the suspension phase, when the casualty either rescues him or herself, if capable, or awaits rescue by another person or persons. After a fall, the body is likely to be in a state of shock. If the casualty is badly injured or unconscious, there is unlikely to be any movement of the legs and there can be serious consequences. The orientation of the body and the comfort of the suspended person, determined to a large extent by the design of the harness and the position of its attachment point to the system, also play their part in the outcome. "

Definition of HHS on Wikipedia.

"Suspension trauma (Syn. "orthostatic shock while suspended"), also known as harness hang syndrome (HHS), or orthostatic intolerance, is an effect which occurs when the human body is held upright without any movement for a period of time. If the person is strapped into a harness or tied to an upright object they will eventually suffer the central ischaemic response (commonly known asfainting). If one faints but remains vertical, one risks death due to one's brain not receiving the oxygen it requires.[1]" 

References

1. http://en.wikipedia.org/wiki/Suspension_trauma

2. http://www.hse.gov.uk/work-at-height/index.htm

3. http://www.elcosh.org/document/1662/d000568/Will%2BYour%2BSafety%2BHarness%2BKill%2BYou%253F.html?show_text=1

4. http://www.outdoorswa.org/files/Harness%20Hang%20Syndrome.pdf

Ceramic coatings can prevent corrosion

Corrosion has long been the bane of the oil industry. Now new approaches and coatings are resolving the difficulties and providing intriguing possibilities for offshore pipelines, explains Tony Collins of EonCoat.

In the oil and gas industry, corrosion accounts for over 25% of failures, according to a recent National Association of Corrosion Engineers (NACE) International report. Corroded pipe repair or replacement costs the industry over US$7 billion per year, based on estimates from NACE. This figure can double when lost revenue, productivity, and spill or leak cleanup costs are tallied.

As deepwater exploration accelerates, protecting offshore pipelines from seawater corrosion is becoming more vital than ever to preserve deeper and more costly oil and gas assets. While offshore pipelines supplement corrosion protection with cathodic protection, the main defense against corrosion remains external pipeline coatings, particularly fusion-bonded, epoxy-powder coatings.

"Corrosion is a major industry challenge," says Scott Justice, Tank Division operations manager of Bolin Enterprises Inc. (BEI), a Casey, Ill.-based pipeline and tank maintenance contractor serving the oil and gas industry.

While traditional corrosion protection has relied mostly on short-lived, physically-bonded coverings of substrate surfaces such as tapes, elaborate three-part coating systems (zinc, epoxy, and urethane), and cathodic protection, these merely attempt to lengthen the time before the steel asset inevitably rusts.

Now a growing number of proactive, oil and gas industry maintenance professionals are turning to a new category of tough, chemically-bonded, phosphate ceramics (CBPC) that can prevent corrosion, extend equipment life, and minimize the cost and production downtime required to recoat, repair, or replace corroded equipment.

New approach

"What caught my eye about [CBPC coating] was its unique adhesion and chemical properties," says Justice, who visited Wilson, N.C.-based EonCoat LLC to view its corrosion testing lab, processes, and procedures for its CBPC coating. "If its hard outer shell is breached or knocked off, it still has corrosion protection where traditional coatings do not. Whether its coating is aged, beaten, or banged around, it still protects the surface. If you remove the outer ceramic shell, the chemical bond with the substrate still stops corrosion at the surface."

In contrast to typical paint polymer coatings that sit on top of the substrate, the anti-corrosion coating bonds through a chemical reaction with the substrate, and slight surface oxidation actually improves the reaction. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints. The corrosion barrier is covered by a true ceramic shell, which resists corrosion, fire, water, abrasion, chemicals, and temperatures up to 1000°F.

While traditional polymer coatings create a film structure, which mechanically bonds to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating's film from all sides of the gouge. Moisture and heat are then trapped by the film, creating a "greenhouse effect," promoting corrosion and blistering. By contrast, the same damage to the ceramic-coated substrate will not spread corrosion because the steel is essentially alloyed. Its surface oxides have been converted into an inert, electrochemically stable metal incapable of supporting oxidation.

Ceramic coatings such as this consist of two, non-hazardous ingredients that do not interact until applied by a plural-component spray gun like those commonly used to apply polyurethane foam or polyurea coatings. Since the components are not mixed and do not meet prior to application, the need for hazardous volatile organic compound (VOC)-generating ingredients is eliminated, as are hazardous atmospheric particles and odor. This means that the work can be done in occupied areas.

"The results of the corrosion tank test were impressive," says Justice. Among the corrosion tests frequently run by the manufacturer of the CBPC product is one where the ceramic coating has gone more than 10,000 hours with no corrosion in a salt spray ASTM B117 test. "If the coating works as well as we hope, it could help to stop or minimize corrosion and extend the longevity of a range of oil and gas assets," adds Justice.

Independent electrochemical corrosion potential testing of the CBPC product also indicates its usefulness for offshore pipeline corrosion protection. Steel plates coated with EonCoat were placed in a beaker of saltwater by Dr. Ki Yong Ann, Dept. of Civil and Environmental Engineering, in a lab at Hanyang University, Seoul, Korea. When voltage was run through the solution and the corrosion rate determined by measuring current leakage across the coating in ma/sq m, the coated plates were found to have no corrosion potential. Any result below "2" is considered to have no corrosion potential, and the coated plates tested at 1.15 the first time, and 0.85 the second time.

For submerged offshore pipeline applications, an anti-fouling topcoat can be added to the CBPC coating, which enhances appearance and reduces barnacle growth.

Unlike organic, carbon polymerbased paints and coatings, which may give a foothold for corrosion causing microbes to grow, ceramic coatings are completely inorganic, so they are inhospitable to mold or bacteria. "Since EonCoat is inorganic, it cannot sustain mold or bacteria growth," says Justice. While not widely considered, the Achilles heel of many traditional corrosion coatings may be in how exact the environmental conditions must be during their application to meet specifications.

"A lot of coating products fail due to changes in temperature, humidity, dew point, and other atmospheric factors during application," says Justice. "As conditions change seasonally throughout the year, it can be difficult to provide perfect coating conditions."

Protective ceramic coatings can be applied on hot or cold surfaces, from 40-150°F in 0-95% humidity, excluding direct rain.

"Since the ceramic coating takes changes in temperature, humidity, and dew point out of the equation during pplication, it can be reliably used in tough environmental conditions that might otherwise compromise the corrosion protection of typical coatings," says Justice.

Cutting downtime

Shane Bartko, a director at TKO Specialty Surfaces, a Calgary, Albertabased tank, pipeline, and structure maintenance contractor, has used the ceramic coating for corrosion control on a variety of oil and gas projects. "To keep a corrosive coating working well, you want one that will be resistant to high temperature, abrasion, chemicals, UV sunlight, and other environmental factors," says Bartko.

The time saved on a corrosion coating project with ceramic coating comes both from simplified surface preparation and expedited curing time. "With a typical corrosion coating, you have to blast to white metal to prepare the surface," says Bartko. "But with the ceramic coating, you typically only have to do a NACE 3 commercial brush blast." Bartko explains that on coating projects using typical polymer paints such as polyurethanes or epoxies, the cure time may be days or weeks before the next coat of three coatings can be applied, depending on the product. The cure time is necessary to allow each coat to achieve its full properties, even though it may feel dry to the touch.

In contrast, ceramic coating is applied in a single coat, with almost no curing time necessary. Return to service can be achieved in as little as one hour.

"With the ceramic coating for corrosion protection, we're able to get facilities back up and running right away after spraying, sometimes in an hour," says Bartko. "That kind of speed in getting an oil and gas facility producing again can potentially save millions per day in reduced downtime. It makes sense to use the ceramic coating anywhere steel is used and may corrode, from pipelines and processing to storage." OE

Tony Collins is CEO of EonCoat, LLC, concentrating his time on commercial applications of Ceramicrete technology. Collins founded Turbine Generator Maintenance, Inc., an independent service provider for gas and steam turbines, in 1986 and sold it in 2007, after amassing customers in 47 states and 15 countries. Collins earned a BS in Mechanical Engineering (1978) from Georgia Institute of Technology.

Managed-pressure drilling riser stack integration

As the deepwater prospects being drilled today address ever more complex conditions, the drilling industry needs to adjust its technology to address the challenges that arise.

The use of conventional "open to atmosphere" drilling methods cannot identify and respond to some of the well events that are encountered in time to prevent them from becoming an issue that in many cases can result in the need to abandon the well.  For example riser gas, which occurs when a gas influx entrained in an oil-based mud breaks out of solution as it is circulated to the surface. This typically occurs about 2000-3000ft below the drill floor, at which point the gas is above the blow out preventer (BOP) in the riser and beyond conventional containment.  The gas can be vented by using the rig diverter system, but this practice is implemented as the very last step in an emergency response and is uncontrolled. One advancement in rig technology used to try and regain control in a situation of gas in the riser is the riser gas handling (RGH) system. Although RGH offers some element of control, it still adopts a reactive approach that does not offer a solution designed to prevent the gas from ever entering the riser.

Closing the loop

Integrating a below-tension-ring (BTR) rotating control device (RCD) into the riser permits the closing and pressurization of the annular returns flow, a key component for MPD. Photo: Weatherford.

Another approach is to integrate a rotating control device (RCD) into the rig's upper riser package, enabling the drilling loop to be closed and pressurized. This integration allows for the installation of a managed pressure drilling (MPD) system that monitors mass flow (flow into and out of the well), providing precise early detection of a hazard, and introduces a means to employ swift preventative measures before a situation escalates into a potentially catastrophic scenario.

One example is detecting an influx wherein an unexpected overpressure zone is encountered, resulting in an influx of reservoir fluid into the wellbore. The MPD software detects the imbalance and calculates what the equivalent mud density should be to balance the well. Automated chokes react to apply surface back pressure, repressing the influx and allowing the driller the time to apply the safest means of circulating the influx out of the circulating system.  MPD is a proactive process that circulates drilling fluid within a contained, pressurized system geared towards riser gas prevention as opposed to conventional drilling circulating systems that are open to the atmosphere and require a reactive human response.  The main components of an MPD riser stack system are:

• A rotating control device (RCD), which creates a pressure tight barrier in the wellbore annulus thus enabling containment and diversion of returning fluids.
• An MPD annular preventer–necessary when replacing the RCD element during a constant bottomhole pressure (CBHP) MPD mode and allows for riser gas handling if drilling open to atmosphere (without the RCD element).
• A flow spool–required during RCD installation to divert returns flow to the rig via a flexible armored hose or gas when drilling in a conventional open to atmosphere setting (no RCD bearing installed).
• An MPD/diverter manifold–required to apply different MPD techniques.
• Surface control system(s),–required to operate the aforementioned components as part of the MPD operations.

Combined, all MPD riser stack components should be automatically controlled by a central intelligent control unit responding to the unique wellbore signals being monitored, including return flow, to enable immediate detection of changes in fluid flow.  This can provide instantaneous detection and response enabling drilling decisions to be made before they escalate to an uncontrollable level.  
Traditionally, the RCD is installed atop the BOP, but on a deepwater vessel, a more sophisticated RCD can be installed below the tension ring as an integral part of the marine riser system. Within the closed loop created by the RCD, changes in pressure are easily detected and effected, while pressure and mass-flow measurements provide real-time data that generates manual or automated changes in choke settings.  Manipulation of the MPD choke manifold leads to changes in annular backpressure at the surface, which immediately increases or decreases downhole wellbore pressure.

MPD in its various forms, presents the possibility to operate in any of the following modes:

• Pressurized mud cap drilling (PMCD), which can be used to drill formations where total circulation losses make conventional circulatory methods impossible.
• Constant bottomhole pressure drilling (CBHP), which for deepwater operations provides the precise wellbore pressure control required to navigate extremely narrow drilling windows between pore pressure and fracture gradient. The ability to dial in and hold a specific downhole pressure without changing mud weight provides a high degree of control and a first response to many pressure-related problems.
• Returns flow control.
• Dual-gradient drilling (DGD)

MPD-enabled rigs
An MPD riser stack, integrated with the purpose of MPD operations, will be the foundation for the future development of floating rigs able to effectively address the challenges of ever-deeper drilling horizons. It enables drilling modifications in three key segments:

• Riser gas handling
• Early identification of downhole flow anomalies such as a kick, loss, breathing or ballooning events.
• A proactive suite of managed-pressure drilling (MPD) methodologies that are bringing non-traditional solutions to complex deepwater drilling challenges such as dealing with uncontrollable losses or navigating narrow pore and fracture pressure windows. 

Despite the success of MPD systems, and the potential they present, their use aboard semisubmersibles and drillships is limited by a host of cost, personnel and deployment constraints on the equipment caused by older rig designs. Extending these MPD advantages to a broader scope of deepwater wells can offer safety, operational and economic rewards, however equipment deployment can be hampered by the inability of deepwater drilling vessels, originally built for conventional open-to-the-atmosphere circulating systems, to readily accommodate it.

RGH/MPD manifold, permanently built into the rig and designed to function as MPD. Photo: Weatherford.

Future developments
Fully realizing MPD benefits in deepwater applications requires a focused industry effort to develop guidelines, procedures and standards for equipment procurement, rig modification and design and perhaps most importantly adequate training for rig personnel.  In the move towards a degree of MPD readiness, modified rigs will have enhanced RGH systems but to go to full MPD capability more upgrades are generally required.  In newly built rigs these needs can be readily addressed; however in existing rigs they can be problematic.

Addressing the problem of MPD readiness will mandate a degree of cooperation across the spectrum of the industry. The most obvious means of achieving this would be for the E&P companies to create the demand by requiring drilling contractors to standardize the integration of a RGH system,  not for riser gas handling as the primary task, but capable of incorporating an RCD (MPD riser stack) for the greater purpose of MPD operations. The greater value to the industry will be an MPD-enabled rig capable of efficiently operating under the daily procedures required during MPD operations once the circulating loop has been closed by the installation of the RCD element. An excellent example of this approach was the design of a newly built drillship which incorporated MPD as part of its capabilities to operate offshore Angola where total mud losses frequently occur.  The success of the project was the result of a collaborative effort between operator, contractor and service company. The installation of a few minor components in the MPD riser stack and rig surface equipment, enabled the rig to rapidly transition from "open to atmosphere with RGH" to full MPD capability thus providing a step change in the rig's capabilities – a transition process that saved 12-14 months rig up time.

In future it may be appropriate to promote a system where increased industry access to MPD capabilities would be driven by mandates set by local and international governing bodies as part of their assessment of  applications for deepwater drilling permits. In lieu of such commitments, a coordinated effort as described is required between the E&P companies, drilling contractors and service companies to create an MPD infrastructure and commitment to it in order to facilitate the ability to drill what would otherwise not be possible.

About the authors

Written by  Guy Feasey and Neal Richard, Weatherford Monday, 09 June 2014 18:18

Guy Feasey is Weatherford's global business development manager. Neal Richard serves as a MPD technical manager for North America at Weatherford.