Replies to This Discussion

Permalink Reply by r k on November 2, 2009 at 15:10

Call me when they get back to work near Marshall Jefferson Harleton... But I'm happy for everyone that's winning right now!

If only O would get off health care and get on green Natural gas auto's with that bailout that's already been spent.

• ▶ Reply

landownerPermalink Reply by A.C.123 on November 2, 2009 at 15:28

"The Kardell #1H was drilled on the eastern edge of Crimson’s “Bruin” prospect where it controls approximately 3,000 acres. The Company is currently in the planning stages of several wells in the “Bruin” area that will further evaluate and exploit these multiple formations beginning in early 2010."

Any ideas where the "Bruin" prospect lies?

• ▶ Reply

Oil & Gas ProPermalink Reply by TEXWS6 on November 3, 2009 at 14:47

This is NOT the biggest well in the Haynesville. Most of the wells that are IP'd in Elm Grove/Red River are doing over 20MMcfd at 8400psi or higher. If you were to draw one of the Red River wells down to 6800psi, it would make 40+MMcfd no problem.

Just because a rock has more calcite, does not mean it is more brittle, or harder. You first need to look at the clay types and maturity, this is what makes a shale ductile or brittle IMO.

• ▶ Reply

landownerPermalink Reply by Bobi Carr ("parker") on November 3, 2009 at 14:55

TEXW6,

Could you explain more please.

I had assumed that these wells were producing as much as 20MMcfd BECAUSE of the high pressure.

Wouldn't opening up the choke lower the pressure and increase flow?

If so, do you know what the choke was on this well?

THANKS

• ▶ Reply

landownerPermalink Reply by Bobi Carr ("parker") on November 3, 2009 at 15:05

I found it: 37/64" choke at 6,824 psi.

PLEASE TELL ME IF I AM GETTING IT?

Tighter choke = higher pressure and less gas produced

Wider choke = lower pressure and more gas produced

• ▶ Reply

Oil & Gas ProPermalink Reply by Les Bamburg on November 3, 2009 at 15:12

Parker, spot on!!!!

Of course there are other factors such as reservoir damage and pipe erosional velocities that limit how large you can open the choke.

• ▶ Reply

landownerPermalink Reply by Bobi Carr ("parker") on November 3, 2009 at 15:14

I kept trying to think of it as a garden hose, but confused myself.

It only seems like a garden hose sprays more water when the choke is tightened BECAUSE it has more pressure.

• ▶ Reply

Oil & Gas ProPermalink Reply by TEXWS6 on November 4, 2009 at 0:41

You all have the idea down, but think of it like this. All wells in a given area have similar bottom hole or reservoir pressure. The LOWER the pressure is at surface, the more drawdown you are creating, the more drawdown you create, the higher flow rate or IP.

I turned a well on in Red River the other day that was doing 18MMcfd at over 9000psi. From a volume perspective you think that the 30.7MMcfd well is more, and it is, but the ETX well's rate potential is less because it takes more drawdown to achieve higher flowrates. Get it?

• ▶ Reply

Oil & Gas ProPermalink Reply by Les Bamburg on November 4, 2009 at 3:54

As Tex no doubt knows, that is the reason companies perform a 4-point test or similar to determine the reservoir's flow characteristics.

• ▶ Reply

Permalink Reply by jffree1 on November 4, 2009 at 4:04

Could you expand on that 4-point test a little further, Les? Some of us are interested.

• ▶ Reply

Oil & Gas ProPermalink Reply by Les Bamburg on November 4, 2009 at 4:24

Jffree, unfortunately my reservoir engineering days are far in the past so others could probably explain better.

Basically a newly completed well is flow tested at four different rates and the operator determines the bottomhole flowing pressures for each of the four rates. This information plus the shut-in bottomhole pressure are used to calculate the well's absolute openhole flow potential. The AOF's should be directly comparable between wells.

The bottomhole flowing pressures can be calculated from the surface flowing tubing pressure.

• ▶ Reply

Permalink Reply by jffree1 on November 4, 2009 at 4:39

So, if I am understanding correctly, the IP reported is not usually what a well will be produced at but, rather, the highest rate achieved during one of those four tests?

• ▶ Reply

• ‹ Previous
• 1
• …
• 3
• 4
• 5
• 6
• 7
• …
• 9
• Next ›
• Page