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Oil And Gas News

Analysis: Big Oil causing high gas prices?

By ROSALIE WESTENSKOW
UPI Correspondent
THE DALLES, Ore., April 3 (UPI)

As gas prices reach record highs, some policymakers say big oil companies are to blame, but the companies say it's not their fault.READ MORE

BP makes new Gulf of Mexico discovery

USA/GULF OF MEXICO: BP has made a new discovery at its Kodiak prospect, located in Mississippi Canyon Block 771, around 60 miles (95 km) off the Louisiana coast, in around 5,000 feet (1,500 m) of water.

The well is operated by BP Exploration & Production with a 63.75 working interest. Co-owners Eni and Marubeni Oil & Gas have 25 percent and 11.25 percent respectively.

The lease was acquired in March 2002 at Lease Sale.

 

 

 

 


Adapting Proven Technologies Yields Higher Penetration Rate and Lower Drilling Cost in the Texas Panhandle 2001 - 2003 By Mike J.Brogdin and Douglas M. Frantz

ABSTRACT This paper describes the evolution of the Operator's three year drilling program in the Texas panhandle, and outlines the adaptation of proven technologies to a new area, which has resulted in increased penetration rates, and lower drilling cost.

Most wells in the Texas panhandle have historically been drilled with rigs on footage contracts, utilizing little or no solids control equipment, and very simple mud systems. Over recent years, prices for drilling expendables and labor costs have increased, resulting in the need for drilling contractors to raise footage rates. Additionally, prices for tubulars and cement have increased, as have drilling mud and mud logging costs.

These rising costs make it necessary to implement changes in drilling practices to drill wells more quickly and efficiently, which will offset the increased drilling costs. These changes include the use of a specially designed solids control equipment system to clean mud containing high concentrations of lost circulation material, optimization of drilling parameters such as bit weight, rotary rpm, and bit hydraulics, and the use of a PHPA polymer mud system.


The use of solids control equipment was implemented first in the areas where lost circulation was severe, and was used primarily to control mud weight to minimize the lost circulation hazard. This system was used very successfully on several rigs in the drilling program, and produced some increase in penetration rate.

When the decision was made to try a polymer mud system in conjunction with the solids control equipment, one rig was selected which had consistently shown above average drilling performance. This rig, Leonard Hudson #2, has drilled a series of wells using the new and refined procedures as a pilot program, with an aim toward expanding the new procedures to the rest of the rigs in the drilling program.

While none of the procedures we have adopted is new or particularly hi-tech, combining the technologies and adapting them to a new area has resulted in significant increase in penetration rate, and has reduced drilling costs in the pilot program.

Program Development
The Operator’s drilling program is located primarily in Lipscomb, Ochiltree, Hemphill, Roberts, Wheeler, and Hansford counties of the Texas panhandle, and several counties in western Oklahoma. The pilot program in place began with the addition of solids control equipment to rigs drilling in areas of sever lost circulation.


Over fifty percent of the mud cost in wells in these areas can be attributed to lost circulation material (cottonseed hulls, cedar fiber, cellophane flakes, etc.), and many of these wells required nitrogen injection in addition to high concentrations of LCM to maintain circulation.   Nitrogen injection is very expensive, and this further elevated drilling costs.


The usual procedure of using fresh water dilution to reduce drill solids concentration and mud weight causes two problems, especially on wells of this type. First, jetting away mud which contains high concentrations of LCM is very expensive, and secondly, it fills up the reserve pit. These pits must be dried up before they can be closed, and this is also very costly.


Our solution to this problem was the incorporation of a linear motion shale shaker to separate the LCM and large cuttings from the fluid via a specially designed LCM saver. The large cuttings are settled out in the first shale pit, which is gated as high as possible. An electric stirrer with a shallow mounted paddle was added to this pit, and is used to keep the upper portion of the pit slightly agitated.

This prevents the fluid and from channeling through the pit, and allows the lighter LCM to flow over the top of the gates, to be reused in the system. The cuttings are then jetted to the reserve pit as needed. The fluid and finer drill solids which pass through the shaker screens are processed by a high capacity centrifuge, and the overflow is returned to the circulating system.


The use of this equipment on wells in the severe lost circulation areas has reduced mud costs by 40-45%, and has eliminated the need for nitrogen injection aeration in all but the most severe cases. Drilling costs were significantly reduced in the severe lost circulation areas using this equipment.

This equipment has also been used in the less sever lost circulation areas with good results. However, the absence of the need for nitrogen injection in these areas, combined with the lower LCM utilization, did not initially prove to be economical.

 Mud System Changes
We had been using PHPA polymer as a shale stabilizing agent for several years, after experiments preformed on Penn Shale samples had shown it to be very water sensitive. The PHPA additions proved to reduce bridging problems and log stoppage in this zone. We had also run high concentration PHPA “clear water” systems in other, less troublesome areas, which produced high penetration rates, and excellent wellbore stability.


It was decided to combine the high concentration PHPA system with the solids control equipment on one of the shallower wells which had lower lost circulation potential, to see how fast it would drill. Chances were made as follows:

Surface Hole: 0-1800’
The surface holes normally spudded with a gel/lime slurry of 30-32 sec./qt. Funnel viscosity.

A small amount of LCM, usually no more than 15-20 sacks, is added to this slurry, to help stabilize the shallow, unconsolidated formations. No additional materials are added after spudding the well, and viscosity is allowed to increase with native drill solids to 38-40 sec./qt. by total depth on the surface hole.

This interval of the hole typically drills fast with few problems, so the only change made was to add 2-3 gallons PHPA per tour to the mud system, beginning at 1200’.

His has proven to help stabilize the red beds, and to provide extra lubricity for running surface casing. Prior to tripping out of the hole to run surface casing, a timed LCM sweep is run. This is used to gauge hole volume, and has allowed us to tailor the amount of cement used to each hole, thereby reducing costs.

Surface to Top of Brown Dolomite
(3400’ +)
Cement is drilled out with water, and water is used to the top of the Dolomite. Instead of using gel/caustic sweeps for hole cleaning, as we have done in the past, PHPA is now used to sweep the hole by slug injection through a polymer pot at the pump suction.


No gel sweeps at all are used in this interval of the hole, but the wellbore is very stable, due to the shale inhibiting qualities of the polymer. The methylene blue test, or MBT, typically shows 7-8 pounds per barrel (ppb) bentonite equivalent during this interval of the hole.

Brown Dolomite-7000’
At the top of the Brown Dolomite, the hole is displaced with fresh gel/caustic premix, of approximately 32 sec./qt viscosity, and the fluid is pretreated with the required amount of LCM for the area. This procedure replaces the heavier, solids laden and salt contaminated mud with a light weight fluid, which reduces the danger of losing circulation in the Brown Dolomite.


The gel/caustic premix is used to provide some clay for adhesion purposes, which makes the LCM work more effectively.

Drilling continues with this fluid, and PHPA sweets are again used for hole cleaning. No additional gel is added after displacement, until such a depth is reached that PHPA sweeps alone are no longer capable of cleaning the hole. This usually occurs at about 6800-7000’.


At this point, the hole is “mudded up” by mixing gel directly into the system. After the viscosity is stabilized at approximately 36-38 sec./qt. the MBT will increase to 9-10 ppb bentonite equivalent.

7000’-Total Depth
After “mud up”, tourly addition of gel are used in conjunction with continued PHPA additions to provide a stable circulating viscosity. During this interval of the hole, the MBT rises to approximately 15 ppb bentonite equivalent, and will approach 20 ppb by total depth.


Fluid properties are maintained in a non-dispersed state until shortly before total depth is reached. This allows the maintenance of lower funnel viscosity, while still providing adequate carrying capacity, and helps maintain the high penetration rate.

The fluid is lightly dispersed near total depth to minimize gelation while out of the hole for logging. This procedure reduces the time it takes to get back to bottom after logging, without breaking down weaker zones.
Log stoppage has been a frequent problem for wells in our area of operation.

The pre-log procedure now in place is to circulate the hole clean in total depth, and then trip out all the way to the casing shoe. The pipe is then tripped back to bottom, and if no drag or fill is encountered, the pipe is tripped out for logs without circulating. This procedure has reduced the frequency of logging mis-runs by over 50%.

Benefits of the PHPA System
PHPA is a co-polymer of a poly-acrylamide and a poly-acrylate. These are several reasons why the PHPA system promotes high penetration rate, and they are interrelated. The poly-acrylamide portion of the polymer chain provides viscosity without the addition of solids, which allows high spurt loss and good chip wetting characteristics. The faster that fluid can flow behind a new chip and equalize the hydrostatic pressure, the more rapidly it can be pumped out of the way so the new chips can be formed by the bit.


The polymer is also highly shear-thinning, providing low viscosity at the high shear rates found at the bit, while retaining the ability to reform gel structures as shear rates decrease in the annulus. This allows good cuttings removal at normal circulating rates, with low funnel viscosity.
The PHPA also contains a poly-acrylate group in its polymer chain. The poly-acrylate group has the ability to attach to solids, and promote flocculation and settling in the mud tanks.

This process enhances the performance of the solids control equipment by aggregating fine solids and making them easier to remove. It also allows flocculated drill solids to settle out rapidly, and be jetted away as the mud tanks are cleaned.
It is important to note that not all PHPA polymer products are the same.

Two different brands were tried during the development of this program, and one performed much better than he other. The polymer which has been the most successful has a high ratio of poly-acrylamide to poly-acrylate. This is sometimes called the x:y ratio.


We believe PHPA which has a low x:y ratio should be avoided, as the higher poly-acrylate concentration causes too much settling. This makes it difficult to carry LCM in the system, and can cause settling of solids in the wellbore on connections and trips, resulting in drag or bridging conditions.


The PHPA polymer is also an excellent friction reducer. This quality lowers friction losses inside the drillpipe, allowing more hydraulic horsepower to be transferred to the bit. It also reduces friction in the bit, and promotes bit life.


We have had several 8000’ Cleveland wells which were drilled with one 12 ¼” and one 7 7/8” bit. And most require only three total bits. This had saved the cost of one to two bits per well.


Another benefit of this mud system is that the shale stabilizing effect of the PHPA has resulted in holes that are more in-gauge. This has reduced the amount of cement required to cement production casing strings. The reduction of possum bellies or washouts in the annulus has also contributed to fewer problems in running logs.

Conclusions
The average penetration for the 1997 drilling program on the pilot rig was compared to the same rig for the 1995 drilling program. 1995 was chosen because this rig had no solids control equipment during this time, and was drilling using conventional mud. The rig had the same toolpusher and crews for both programs.


Figure 1 illustrates the marked improvement in penetration obtained with the new drilling procedures, in average feet of hole drilled per day, which has increased by 52% on the shallower wells, and 59% of the deeper wells. These wells are now being drilled 3-4 days faster than previously, using fewer bits, and having virtually no hole problems.
Figure 2 illustrates these penetration rate comparisons in feet/hour.


Figure 3 illustrates the relative mud costs of the two drilling programs in cost/ft. the mud cost for the shallower wells is 7% lower using the new procedures, and is 18% lower on the deeper wells.

The savings in mud cost offsets the cost of the solids control equipment by one-half on the shallower wells, and more than pays for the equipment on the deeper wells.
The attitude and dedication of the personnel involved are very critical in the implementation of this program. It has been attempted on several other rigs concurrently with Hudson #2, with mixed results.

Two other rigs in the program have come close to matching the performance seen on Hudson #2.
The other rigs on which this has been attempted have been unsuccessful, for several reasons. The successful implementation of this program requires full cooperation of all rig personnel.

It also requires full cooperation of all rig personnel. It also requires the willingness of the contractor to optimize all drilling parameters toward obtaining maximum penetration rate. The mud system itself requires close monitoring by the derrick hands and mud engineer to obtain maximum performance, and factors such as mud tank design even play a part.


Some of the rigs operating in this area do not have mud tanks which are suitable for running this system, without undergoing modification, and this has not been possible on all of the rigs. However, the use of solids control equipment alone has proven to be beneficial on all rigs drilling in the lost circulation areas, regardless of design.


The eventual adaptation of this program to all rigs in the drilling program will produce significant savings in drilling costs, especially if the rigs are placed in daywork drilling contrats.


 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2001 RMS CONSULTANTS
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