Friday, May 29, 2015

Production Metrics

With new wells results from Encana, I've updated some production metrics below.


Tuesday, May 26, 2015

TMS Well Count

The TMS play has reached the 84 well count with 71 producing, 12 drilling yet not completed (DUC), and 1 currently temporarily abandoned.

Wednesday, May 20, 2015

Cumulative BOE Through Time

I believe that the first "apples to apples" comparison on production can be made at the six month mark.  This provides time for each well to clean up and establish a decline curve.  The chart below presents the cumulative barrels of oil equivalent at 6,12, 18, and 24 month timeframes. One interesting observation is that several of the "Top 10" at 6 months haven't even reached a year yet. This is a great sign of improving frac jobs.  Note that the state regulatory agencies are 2-3 months behind.

Sunday, May 17, 2015

Cumulative Oil Production

To keep with the theme of oil production to date in the TMS, the chart below compares wells based on their monthly oil cumulatives. Only wells with an initial potential of 150 bbls/1000' are displayed.

Monday, May 11, 2015

TMS Production Treemap

Below is a treemap of cumulative TMS well production to date. The monthly production data is sourced from SONRIS and the Mississippi Oil & Gas Board.  SONRIS is current through March, 2015 and the MSOGB through February, 2015. The Crosby 12-1 is still the largest producer, but there are some wells on the fast track such as the Blades 33-1, Pintard 28-2, and the Lyons 35-2.


Thursday, May 7, 2015

Goodrich Petroleum Earnings Call - Q1 2015

Goodrich provided an excellent update on their TMS activity yesterday in their earnings call. Most impressive is their significant reduction in drilling and completion costs.
Here are the TMS highlights:

have increased our backlog of drilled but uncompleted wells in the TMS to 6 as of the end of the quarter.
raised approximately $148 million during the quarter to strengthen the balance sheet and enhance liquidity.
we now have a record-setting well, brought in by one of our peers in the middle of our core acreage position at over 1,900 barrels equivalent per day. The top 10 wells completed in the play, as shown on Slide 6, have an average peak rate of approximately 1,500 BOE per day and are 93% oil. These wells are producing on, or in most cases, above our 800,000 BOE decline curve
Our optimized criteria, as shown on Slide 8, is that wells land in the lower portion of the TMS, they are drilled with a minimum of 5,000-foot laterals. The fracs are at least 1,500 to 1,600 pounds per foot, and hybrid frac jobs are pumped, which is a combination of slick water, which creates complexity, followed by gel that transports the sand out into the complex fracture network.
We are now seeing a good correlation between results and proppant per foot, as many of the recent well results from one of our peers that pumped as much as 2,400 pounds of proppant per foot have seen both higher initial rates, flatter curves and higher estimated reserves. As we return to a more normal oil price environment, we think a return to longer laterals with higher proppant concentrations will generate superior results.
The Crosby well has been the signature well for the play, as it has been online now for over 24 months and has produced well over 200,000 barrels equivalent in that period. In addition, several wells have come online over the last 5 to 8 months, including our CMR/Foster Creek 31, which is shown in light blue, and has tracked well above our Crosby well for 7.5 months. In fact, several industry wells in the core are currently flowing at or above the Crosby well over the first 6 to 8 months.
Although we see the benefit in longer laterals, there is an added cost, and our results in Area 3, as shown on Slide 11, are outstanding from shorter laterals. Our Blades, Verberne and Williams wells continue to be top outright performers. And the Blades well, which is completed with a 5,000-foot lateral, is our top producer per lateral foot. The Blades and Williams wells have reacted very well to artificial lift, and we plan on putting wells on artificial lift sooner in the future to maximize early time performance and shift the curves even higher.
Area 3 comprises almost 100,000 net acres and is where you'll likely see a high percentage of our 2015 development, including 2 well pad wells, which will further drive down well costs. We also intend to pump higher concentrations of proppant on future wells, which should further enhance productivity, similar to other industry wells of late. Of the 6 wells drilled but waiting on completion, again, 5 wells will be completed in Area 3.
Area 4 on Slide 12, although not currently identified as core, continues to provide upside potential, as the Beech Grove and SLC's are performing fine.
On Slide 13, we show all 30 wells compared to our type curves. And you can see the newer wells are outperforming, as completion methodology has been optimized.
When you average those wells into a composite curve, as shown on Slide 14, we are producing on or above our 700,000 BOE curve. We would expect this curve to increase over time as the newer outperforming wells flow through the curve.
When you bake in the variables mentioned earlier, we are calculating wellhead rates of return at 32% to 48% for our mid-case curve at $65 to $75 a barrel. And we have 1,500 net locations in the core at 100-acre spacing.
the real improvement has come lately, as we are currently projecting 24-day average drill times for our 5,000-foot laterals in Area 3, again, where approximately 70% [indiscernible] for 2015.
We have made tremendous progress operationally. And the reduction in drilling days from 40 to 24, as shown on Slide 16, is saving approximately $1.4 million in drilling costs per well. When combined with the sharp drop in service costs, in particular on the completion side, we're seeing approximately $3 million less cost per completed well for single-well pads and another $600,000 in savings for 2-well pads. The $10 million estimate for a single-well pad and $9.4 million for a 2-well pad, assumes 5,000-foot laterals and the higher proppant concentrations, which are generating the recent outperformance from offset wells.
As a reminder, as shown on Slide 17, the TMS is 92% to 98% black oil, priced at Louisiana Light Sweet, or LLS, minus $2 at the wellhead, which has us currently receiving approximately $66 a barrel, an approximate $4 premium to WTI.
we do drag a rig back in at the end of the second quarter, not a whole lot of that CapEx is baked into that. I would say we're not -- we don't plan to have one rig running full-time, but for most of the back half of the year, we would expect that to happen.
at least 70% of our activity in '15 is planned for Area 3. It's really likely going to alternate a little bit with Area 1, with one exception. We have the T. Lewis well in Area 2 that's 1 of the 6 wells that is scheduled for completion. So I think a concentration, certainly, in Area 3, Tangipahoa Parish in particular, with an occasional well drilled in Area 1 and the one completion in Area 2 is how it currently reads.
if you take these most recent wells and play them out, they're certainly going to be north of 800,000-barrel EURs. So even going back now with that in mind, taking a look at the 700,000-barrel curve, as Rob outlined, generating very attractive rates of return for all the reasons he outlined, even at $65 to $75 a barrel. So we feel -- we still feel great about the play. We think it's going to be a tremendous play and are anxious to see oil continue to do what it's been doing of late. And you'll see us pick up our activity level in the second half of this year.
So I think the 30-day average is probably close to what, 875 to 900 in our budgeting or modeling.
We talked about the Kent well. We still have plans to go back in and drill those frac plugs out. Going forward, as we mentioned in the press release, these dissolvable plugs basically eliminates not only about $0.5 million of costs, but the necessity to go in with coil tubing and drill the plugs out. So that's a material change operationally, both from a cost standpoint and just risk mitigation.
What we were using a year ago that we had problems with were permanent plugs that had a 2-inch ID, or interior diameter, and we were using dissolvable balls to create pressure [indiscernible]. So this is an entirely -- this, as Rob described, is a fully dissolvable plug, fairly new on the market. I think they first rolled them out in August, September of last year. The utilization of those plugs has ramped up dramatically in the last 6 months. We used them on the 81 and 82 with absolutely spectacular results. We let the well shut in for about 72 hours, plugs dissolved, and we started flowback. So in this case, the entire plug itself was dissolving, not just the ball.
our plan is, is to definitely go to the 2,000 to 2,400 pounds per foot. You do pump a little more fluid with it just in proportion to the increased amount of sand. But very important that you stay with the hybrid job, as we've been doing. It's just -- it's a pretty nice correlation or -- the R square is pretty high when you look at proppant per foot. Certainly, you can argue lateral length also has a pretty good correlation, at least on flattening curves. But we're-- it's pretty convincing, and that's why you -- that's why we baked that into our current well estimates. And you'll see us pumping bigger frac jobs.
We're about 300 feet right now, which is higher than what we had been. But it's all about your perf clusters and the spacing of the clusters and then the proppant per foot. So regardless if it's 250-foot intervals or 380-foot intervals, the proppant per foot is basically the same. So we're going to go to 300. Currently, some of the other operators are widening those intervals, but again, increasing the sand amounts. So we feel pretty good that the 300 is a good fit for us.
our best well to-date on a per lateral foot is our Blades well. So clearly, we believe there's some incremental naturally occurring fractures in that area. We really like it. And yes, we have seen really, really good drilling performance in that area. I think all of those wells have come in, almost every single one of them, many of those wells of late have come in with the best drill times we've seen to-date. So it's just -- we've done some different things from a technical standpoint with our downhole assembly, which is certainly helping, but that area does drill quite well.
without the benefit of longer history on these more recent wells, the 6,000 -- 5,000 to 6,000-foot laterals at $10 million to slightly more than that, are generating very good rates of return. But there is going to be a bias towards going longer because our experience in the Eagle Ford has been -- and certainly, you're seeing at the Haynesville, too, is the longer laterals ultimately make more sense. But it's all a factor of rates of return and commodity markets that we currently play in.
don't really have one rig scheduled for the entire second half, although for most of the second half, we will be drilling with that one rig. Obviously, cycle times are much faster now with the 24-day drill time. You're probably looking more like 45 days spud-to-spud instead of 60, where we had been. We've given some guidance on the number of wells that we're going to drill and complete. It's on our inventory chart. I believe it's 11 gross, 8 net wells. This is obviously 6 gross completions plus the 2 that we completed, the 81 the 82. So we'll be at 8 gross once we complete the 6 that are currently shut in. So another 3 gross, 2 net wells after that probably makes sense, based on our current budget. But as Gil said, look, if oil prices continue to rise, you could see us accelerate a bit over and above that.
the B-NEZ 1 and 2 and Tangipahoa Parish in Area 3 is a 2-well pad.
We did release that rig. Obviously, that was roughly $25,000-a-day rig rate. We're seeing $16,000, $17,000-a-day rates currently, which is baked into this $9.3 million estimate for the 2-well pads.
lease retention. We have a $10 million budget this year, which allows us to maintain the core position of 150,000 acres, plus as much as 100,000 acres by the end of the year. So that's one aspect of it. If you look at our lease position, we have more acreage in Area 3, of 100,000 acres, and our goal there is to get out ahead of any lease expiration. So I think you'll continue to see a skewing of our activity in Area 3 versus the other areas, which are a little bit -- a little longer-dated lease expirations or are under continuous drilling provisions already, which is very manageable. So just because of the size, because of the lease schedule, I think you'll continue to see us skew towards Area 3.
We do have a little bit of microseismic work that was done sometime ago out there that indicates you probably can downspace from that. Obviously, with our footprint being what it is, at 100-acre spacing, we've got more wells to drill and more capital to deploy than we can possibly even contemplate over the next 10 years or so. So it may get tighter. I think if you look at the rock properties and rock qualities, plus the microseismic, it certainly would suggest you could layer in an additional well in between those.