Thursday, October 24, 2013

Coiled Tubing Challenges

The TMS has been plagued with challenges while using coiled tubing to drill out the plugs in the horizontal wellbore.  This is not my area of expertise, so I've aggregated some online content to provide some perspective into the process and alternative options.  

A nice overview:
Working in the shale plays poses some new challenges for coiled tubing. Currently in these fields a large majority of the wells drilled are horizontal wells. Due to the length of horizontal sections that are now being drilled, one of the challenges has been horizontal reach with the coiled tubing due to helical buckling.

A 2-3/8” deep well unit working in the Eagle Ford Shale.
Most wells in these shale plays require some type of stimulation to maximize production. Currently multi-stage hydraulic fracturing is the method of choice. During the hydraulic fracturing, the well is treated from the bottom up. The treatment begins with the bottom treatment zone or stage being perforated and treated. After the treatment is complete a composite plug is set above the zone to isolate it from the subsequent treatments (in the long horizontal sections the plugs are pumped down when they will no longer fall with wireline). The next zone up is then perforated and treated and another plug is set. This will continue until the entire horizontal section has been treated. Wells can have 15 or more treatment stages depending on the length of the horizontal section. After the final zone has been treated the plugs need to be removed from the well. It is not economical to attempt to pull the plugs so a coiled tubing unit is used with downhole motors and mills to drill these composite plugs. These jobs are called “coiled tubing drillouts” or CTDO.

Buckling of the CT 
One of the challenges associated with CT operations on extended-reach shale wells is to utilize techniques to delay the onset of CT “buckling” so that CT can reach the target working depth. Buckling of the CT occurs when the axial force required to push the CT to the toe of the well exceeds a critical level. When pushing CT into a long horizontal lateral, the CT first buckles into a sinusoidal shape. As the CT is pushed further into the horizontal section, the increased axial force applied to the CT (required to overcome additional friction between the CT and wellbore) will then cause the CT to deform into the shape of a helix inside the wellbore, which is referred to as helical buckling. Frictional drag forces on the CT will increase exponentially when the axial force applied on the CT exceed the critical helical buckling limit. If additional axial force is applied to helically buckled CT, it will rapidly reach a point where 1 percent or less of the additional weight applied at surface reaches the downhole end of the CT. This is known as CT “lock-up” and will prevent any further movement of the CT into the horizontal lateral.

Increasing the OD and wall thickness of coiled tubing will help extend the reach of coiled tubing. But it comes with the added size and weight of the extra coiled tubing and larger equipment. Larger, two-trailer coiled tubing units are being manufactured to accommodate the extra weight and bulk. One of the larger two-trailer CTUs has been utilized in the Eagle Ford Shale in South Texas. This unit can carry 23,000′ of 23/8″ coiled tubing. It is 12′ wide x 14’8″ high x 61′ long and has a HR-6100 injector with a pulling capacity of 100,000 lbs. and snubbing capacity of 50,000 lbs. These units can weigh up to 200,000 pounds with a full reel of tubing and are permit loads in the lower 48. These units are not single purpose, their main use is for milling plugs following frac jobs but they also have a history of being a go-to service in horizontal wells for operations such as coiled tubing logging, toe shots (frac prep) and coiled tubing fracturing.

Horizontal well completions have also led to a step change in the coil tubing manufacturing business. Three years ago the primary market for coiled tubing was vertical well cleanouts and the typical size was 11/2″ and 13/4″ coil with lengths ranging from 17,000′ to 20,000′. Today the horizontal extended reach wells have changed that market mix to 2.00″ and 23/8″ strings ranging from 18,500′ up to 24,000′ in length.

Larger coil tubing sizes 
The challenges for coil tubing in the horizontal wells is to make sure the plugs are properly drilled out, getting to the end of the horizontal sections and removing all the debris from the wellbore. The key to accomplishing all of these challenges is the larger coil tubing sizes, higher flow rates and higher surface treating pressures. So not only has the size of the coil strings changed, the wall thickness and grade of coil strings have changed too. In today’s shale play market higher grades of coil tubing such as QT-900 and QT-1000 have become the predominant grades of choice. Wall thickness designs have also changed. In order to operate at surface treating pressure from 7,000 to 10,000 psi, which is needed to clean out these sections and have the tube strength needed to snub in the horizontal sections, string designs have changed to heavier walls usually ranging from .175″ to .203″ wall thickness. As the length of the horizontal sections of the shale plays grows so will the demand for higher strength, larger OD, heavier wall and longer length coil tubing strings. As coiled tubing sizes increase, the need for larger bore pressure control equipment also increases.

Larger bore pressure equipment
Larger bore BOP’s are required to run the larger diameter mills, the mills are up to 43/8″ diameter, which is too large for a 41/16″ BOP. The bore size has stepped up to a 51/8″. Depending on the surface pressure it could be 10,000 psi or 15,000 psi working pressure well control equipment. The BOP stacks used have a dual barrier philosophy. The dual barrier provides two barriers between the well bore and the environment in case of an emergency. The BOP will have a blind shear ram in the stack that will be able to shear the coiled tubing and provide a seal after shearing. The Blind shear rams used have been qualified to the most recent API specifications. The additional rams used in the BOP stack include pipe rams, slip rams and grip seal rams. The grip rams are bi-directional and are qualified to hold the coiled tubing and prevent the tubing from moving so the pipe rams can seal on the tubing.

The BOP stack features include integral equalizing valves, hydraulic ram change, low torque bonnet bolts, metal x metal well bore seals, indicator rods on all rams, and Viton ram seals. The two main bore sizes used are 41/16″ and 51/8″. Depending on the type of CT application that is being run will determine which BOP stack will be required.

The uppermost piece of equipment in the BOP stack is the Stripper Packer. The latest technology has a design that has two individual packer elements. These high-pressure packer elements will seal around the coiled tubing while it is stripped in and out of the well at pressure up to 15,000 psi. The unique feature of this tool allows the packers to be run alone or in combination. Inhibitors can also be pumped between the packer elements to lubricate the coiled tubing.

The lower section of the Stripper Packer has a special rotating flange that provides a means to allow a flanged rig up to align the injector, wellhead and the spool if there is a misalignment. The rotating flange was designed for the high-pressure flanged rig ups and has reduced the time spent on alignment in tight job sites dramatically. 

Milling operations
The ability of keeping the motor and mill on bottom drilling efficiently and reliably is an economical factor that cannot be overlooked. Drilling 15+ plugs in a single run not only requires an experienced operator with a knack for drilling plugs, it also requires top-of-the-line equipment.

What is needed in shale play milling operations is an economical, conventional type, power section that can generate higher power and torque, has the proper elastomer to deal with temperature extremes found in the shale plays, and is capable of running on commingled fluids containing N2 or air. A power section capable of generating 75 percent more torque and power (compared to current offerings) allows the BHA to better withstand sudden tension releases in the CT without stalling and allows the mill to “drill through” plugs without having to constantly cycle the CT string off bottom. In addition, a power section capable of generating high differential pressures (i.e., between 2500 – 3300 psi on a 27/8″ power section) means the tool operator can predict potential stalls more readily. As a result, fatigue damage to the CT is substantially reduced due to less frequent off bottom cycling while at the same time increasing ROP. A power section delivering these properties would be a welcome addition to the industry; lowering initial expenditure, delivering increased performance, and reducing costs due to CT cycling fatigue.

Vibration for extended reach 
Vibratory tools have been used for several years to overcome the extended reach issue with CT. A tool that can effectively excite the CT string axially, along its entire length, will reduce the fictional drag between the CT and the wellbore tubular. This will delay the onset of helical lockup and also offers a side benefit of shorter plug milling times. There are two main types of CT vibratory tools available. One that utilizes a piston to create the pulses (similar to a downhole hammer) and one that uses a patented rotor/stator arrangement driving a valve pack that creates the pressure pulses. Piston style tools, by design, have to completely block the fluid flow to achieve vibration. This will affect the flow of fluid to the power section and can affect its performance. They also are erratic, and sometimes uncontrollable, when pumping a multiphase fluid or straight gas. The vibration is usually localized close to the tool. The other type of vibratory tool that uses the rotor/stator combination never completely blocks the flow of fluid. The operation of this type of tool is smooth and controlled, regardless of whether a multiphase liquid or straight gas is being pumped through it. This type of tool is widely regarded as the standard tool to use in the shale plays to gain extended reach and decrease plug milling times.

Roller cones 
Roller cones are fast becoming the defacto in composite plug milling in the shale plays. A series of roller cone bits, sized from 41/2″ to 43/4″, are in trials now. They feature improved hydraulics and sealed bearings, along with improvements to the roller cone bearing surfaces. Compared to current bit offerings, early indications are extended bit life and improved hole cleaning.

Straightening the CT 
Another effective method of delaying the onset of buckling is to straighten the coiled tubing. Although the idea of straightening the coiled tubing has been around for a while, the concept has been effectively utilized in the long horizontal sections of the major shale plays. Contractors have found that removing the residual bend from the coiled tubing can reduce the well bore friction to extend the reach. Most cases the downhole end is straightened to cover the distance from TD to the top of the build section.

Friction reducers 
Another method to delay the onset of buckling is the use of friction reducers and other chemicals. Use of friction reducers is the simplest method because it is an additive to the mud system and utilized “as needed.” Most mud companies will provide personnel, and chemicals for coil tubing drillout operations. CTDO require blended sweeps to clean out the wellbore after each plug is drilled and regular additions of friction reducer, to the active fluid system. In addition surfactants, in conjunction with friction reducers, helps reduce friction as well as torque and drag during coil tubing operations. Friction reducer also reduces the surface tension of the drillout fluid which in turn aids in friction reduction, allows the fluid to more easily flow back, and minimizes the amount of friction reducer required during the CTDO. Other optional products that may be used during a CTDO are lubricants and coil tubing corrosion inhibitor.

Take your pick 

These are some of the options to the challenges of coiled tubing while working in the long horizontal sections now being drilled. There is no hard and fast rule about which method or methods should be used. Some operator’s use the economical approach of “just enough to get me there” and others use all of the above, “remove all doubt” approach.


A nice comparison of workover rigs versus coiled tubing: 
Workover Rig
Many times, remedial work constitutes employing a workover rig to repair the well. Similar to a drilling rig, a workover rig is smaller and requires no mud pumping or pressure-control systems. A workover rig is used to retrieve the sucker rod string, pump or production tubing from the well or run wireline cleaning and repair equipment into the well. It is important to note that with workover activities, production must be stopped and the pressure in the reservoir contained, a process known as “killing” the well.

Coiled Tubing
A cost- and time-effective solution for well intervention operations employs coiled tubing. Instead of removing the tubing from the well, which is how workover rigs fix the problem, coiled tubing is inserted into the tubing against the pressure of the well and during production. Coiled Tubing Coiled Tubing Source: US Department of Labor The coiled tubing is a continuous length of steel or composite tubing that is flexible enough to be wound on a large reel for transportation. The coiled tubing unit is composed of a reel with the coiled tubing, an injector, control console, power supply and well-control stack. The coiled tubing is injected into the existing production string, unwound from the reel and inserted into the well. Coiled tubing is chosen over conventional straight tubing because conventional tubing has to be screwed together. Additionally, coiled tubing does not require a workover rig. 

Because coiled tubing is inserted into the well while production is ongoing, it is also a cost-effective choice and can be used on high-pressure wells. Coiled Tubing Operations All performed on a live well, there are a number of well intervention operations that can be achieved via coiled tubing. These include cleanout and perforating the wellbore, as well as retrieving and replacing damaged equipment. Additionally, some advances in coiled tubing allow for real-time downhole measurements that can be used in logging operations and wellbore treatments. Enhanced Oil Recovery (EOR) processes, such as hydraulic and acid fracturing, can also be performed using coiled tubing. Furthermore, sand control and cementing operations can be performed via coiled tubing. 

Source: Rigzone

A nice video illustrating coiled tubing being used to drill out plugs:

Wednesday, October 23, 2013

Encana Earnings Call - 10/23/13

Here are the TMS highlights from Encana's conference call today:

Mike Rimmel - Barclays Capital
Hi, thanks for taking my questions, two from me. Would you mind talking about any infrastructure constraints you guys maybe facing going into the next year particularly wondering about Piceance area? And then, the next one is, just wondering whether there are any updates on the TMS, I know you were in the middle of [indiscernible] wells last quarter? And that’s it from me, thanks.
Michael G. McAllister - Designated COO
Hi Mike, it’s Mike McAllister here. Yeah, first on with respect to infrastructure constraints, we were actually in really good shape here in Bighorn. We have contracts to take all of our product out of that area with – so we’re feeling very confident with respect to that. Up in Peace River Arch, we actually again have, we’re in really good position, we have aligned to our growth out of the Peace River Arch with infrastructure actually that’s being built. And that’s in private chip as well. And I think your third question was related to the TMS and three of the last four wells are meeting, are actually exceeding type curve. The other well, the fourth well if you will below type curve but we understand and that specific well that is was frac communication and re-interference that affected that. So we understand what that issue is and ready to move forward.
Matthew Portillo - Tudor, Pickering, Holt & Co.
Great. And then, just in regards to TMS, you mentioned that the curves are performing at kind of your expectation on three of the wells, could you remind us how you guys think about the EURs in the play and then what you need to see from here to progress that towards commercial development?
Doug Suttles - President & CEO
You know Matt well, well Mike grabbed some of the data, you know, I think the way we are thinking about the TMS is that, we really need to gain the confidence, we really need to move forward rapidly there which is around the type curve not only the early performance on the type curve which as Mike said, we are very encouraged but I would like to get a bit more time under our belt. The second thing is, we have a massive land position there, I think, over 300,000 acres and as we think about that play we need to actually make sure we are confident in the rocks across the play. And the last thing is confident that the costs are coming down, this will be a big focus in 2014 and I hope by the time we exit the year, we actually know the answers to those questions.
Michael G. McAllister - Designated COO
And just with respect to what we’re targeting approximately 600,000 barrels oil equivalent per well.
Matthew Portillo - Tudor, Pickering, Holt & Co.
Okay and just one clarification there, so as you guys think about the wells you’ve seen so far is, is the big takeaway that we should think about it effectively the initial production is meeting your curve expectation, but you’d like to see longer term data before gaining additional confidence in that kind of getting to that 600,000 curve?
Doug Suttles - President & CEO
Yes, absolutely with all of our plays, you see initial IPs very encouraging, but really we want to see sustained production performance and see how well it matches, what are resolute modeling telling us, so really need to see some history there to give us the confidence.
Michael Dunn - FirstEnergy Capital
Good morning or good afternoon everyone. Couple of questions one on the TMS one and the San Juan, on the TMS guys just wondering what your latest thinking is on completions in terms of I believe on the last call or earlier this year, you were talking about targeting completing it above the rubble zone and it seems like we have had maybe some mixed results above or maybe a couple of wells what might like they may have been better below the rubble zone, so just wondering if you are still confident in targeting above the rubble zone? And in the San Juan, you have mentioned 400 to 500 barrels a day, 30 day period there, how should we think about that relative to the targeted EUR you guys talk about the 550,000 BOE EUR, is that sort of above that or on trend with that EUR you talked about? Thank you.
Doug Suttles - President & CEO
Yes, I think Mike this is Doug, I think on the TMS, I think we would probably need to get you on that level of detail about the completion, I can tell you that the big focus there has actually been on changing the completion design itself, changing the frac design which clearly made a big improvement in the last few wells. But I would also caution that I don’t think we believe we’ve yet get the best formula and that will be part of the plan in 2014 and Mike if you want to pick on them San Juan well and --

Entire transcript:

Sunday, October 13, 2013

Contango Applies For TMS Units

Conterra Company, Contango's subsidiary, is applying for two TMS units in Northeast Spillman Field (W. Feliciana Parish).  Both units are 995 acres and are just east of Encana's existing units.  The TVD of the TMS in this area is -13300'.  Being located inbetween three underwhelming Devon completions, this will present an interesting opportunity for Contango to prove the value of the area.  We look forward to having a new operator joining the mix.

Crimson and Contango just recently merged:

Friday, October 11, 2013

EOG Paul 15H-1 Results

The results for the 15H-1 have been posted on SONRIS.

COMP 07/01/13: OIL, TMS RA SUA, 181 BOPD, 140 MCFD, 773 GOR, CK OPEN, GVTY 47.5, BWD 118, BS&W 39%, FP 448, CP 448, PERFS: 11682'-16348'

This well lost a string of pipe in the lateral and has been producing with this obstruction. Deciphering the result is not possible.  I estimate this local area to have ~90' of pay and 118' of higher resistivity which should result in attractive rates and economics.  I would expect EOG to twin this location at some point in the future.

Thursday, October 10, 2013

Goodrich Announces The Result For The CMR-Foster Creek 20-7H-1

Goodrich announced the results yesterday for the 20-7H-1.  Once again, we have a well that encountered issues while drilling out the plugs.  Losing a bottom hole assembly is not the norm.  The current thinking appears to be that coiled tubing is not the best approach for this process in the TMS.

A detective is required to assess the results from the well being that the initial test is only from a portion of the completed lateral.  The quick "back of the envelope" math would say that 527 boepd over 2100' could possibly equate to 1581 boepd for a 6300' lateral or 1555 boepd for the 6200' that was actually stimulated.  That's not a stretch, but we don't know for sure.  

I believe that the reservoir rock in this location is as good as the Crosby 12H-1.  The goal for this well was repeatability.  I'm confident that our stellar engineers will solve this problem in the near term.  The goal will be to not add additional costs, but increase the probability of completion success.

HOUSTON, Oct. 9, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced the completion of its CMR-Foster Creek 20-7H-1 (99% WI) well in Wilkinson County, Mississippi. The well was successfully drilled with a 6,200 foot lateral and fracture stimulated with 23 stages but encountered completion issues while drilling out the frac plugs with coiled tubing resulting in the loss of a bottom hole assembly and fishing tools in the well. The Company replaced the coiled tubing unit with a workover rig in an attempt to remove the downhole tools but fishing operations were un-successful. The well was subsequently placed on production from the approximately 2,100 feet of usable and unobstructed lateral.
The well has reached a 24-hour peak production rate of 527 barrels of oil equivalent ("BOE") per day, comprised of 500 barrels of oil and 174 Mcf of gas on a 16/64 inch choke from the 2,100 feet of lateral.
The Company is currently drilling the lateral of the Huff 18-7H-1 (97% WI) well in Amite County, Mississippi, with plans to go to two rigs later this month.
The Company currently has in excess of 300,000 net acres in the Tuscaloosa Marine Shale.

The entire press release:

Tuesday, October 1, 2013

Encana's New Strategy

A good article outlining Encana's corporate strategy:

In his first 100 days on the job, Encana CEO Doug Suttles made it clear that significant changes are in store for Canada's largest natural gas producer.
The company has seen its workforce drop by about 300 people so far this year and, when 3,800 employees gather for a town hall meeting with the new boss today, they will all be well aware Suttles has told investors current organizational structure is more aligned with Encana's past than its future. "Maintaining the status quo is not an option," Suttles has said.
When he steps onto the stage at the BMO Centre to address staff in Calgary, it will provide many of them their first real opportunity to see and hear the man who has been charged with reviving what was once Canada's dominant oil and gas producer. For some, it could also be the last time.
Suttles, who was hired from BP in June, has said Encana will develop fewer properties, bring in a new corporate structure and capital controls as well as better aligning its compensation with persistently low natural gas prices. The company, which had 4,197 employees at the end of 2012, has cut seven per cent of its staff in the first half of this year and
Suttles warned after the second quarter that further cuts - but not a general layoff- are likely through year end.
That's quite an introduction - his employees will be keen to see what he does for an encore.
They didn’t need to wait long. On Tuesday morning Encana announced five senior executives – including Jeff Wojahn, president, Eric Marsh, senior vice-president, of the USA Division – would be leaving as part of a new organizational structure.
“Doug wants to say it face to face with staff and take their questions,” company spokesman Jay Averill said in an e-mail Monday. 
Suttles will hit the road this week to speak to staff in Colorado and Texas.
The issue of job security is bound to be top of mind for some in the audience but Suttles will present a clearer vision of his overall strategy for the $13-billion market cap company. He has said Encana will exit a number of its 28 plays in North America to focus on top assets such as the Duvernay in Western Canada and the Tuscaloosa Marine Shale in the Southern U.S. Suttles told the Barclays investment conference in September he would reveal details of the strategy in the weeks ahead and incorporate them in Encana's 2014 budget.
"We need to change in a big way, in a bold way," Suttles said in New York.
Those types of statements are bound to resonate through a company but Averill noted the sentiments were rooted in the company's internal feedback process.
"When change is spoken about it's quite natural for people to wonder how it will specifically affect them," said Averill. "Doug's comments about change ... were actually drawn from staffsurveys where the vast majority of staffhave said they want and expect significant change."
Encana has been in change mode for some time, selling assets - mostly dry gas properties - after losing half its market value since 2010. The stock has been held down by the pronounced decline in natural gas prices which began in 2008, the year before former CEO Randy Eresman spun out Encana's profitable oilsands business as Cenovus Energy.
Encana shares were up 21 cents in Toronto after the announcement Tuesday to $18.01 — still well off the 52-week high of $23.86. Encana shares were up 21 cents in Toronto after the announcement Tuesday to $18.01 — still well off the 52-week high of $23.86. 
The changes promised by Suttles may be big and bold but they will pave the way to an era of restraint.
When natural gas were robust five years ago, the attitude in the oil and gas industry was for aggressive production growth. After the fracking revolution unlocked vast new supplies and prices collapsed, companies like Talisman Energy and Encana are putting a premium on financial discipline and profitable production.
Suttles has sought out internal and external assessments of Encana's assets and business strategy to augment his own review of the company's strengths and weaknesses. It's already shifted the focus from dry gas to produce higher value crude oil and liquidsrich gas.
While Eresman had been optimistic of a return to better natural gas prices, Suttles has warned North American gas prices will be "rangebound" from $3.50 to $4.50 US per million British thermal unit in the next few years. He's pledged to make capital discipline key to his strategy and has said Encana would "evaluate" its 20-cent quarterly dividend payment as part of its strategic review.
As part of his pledge to investors, Suttles has said "Encana will be back to winning" - it just this time around it may be winning small rather than winning big.