Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on June 10, 2012 at 5:08

Spud dates for oil wells in the Caddo Pine Island Field go back to circa 1905.  The field is so old that it was discovered before conservation regulations existed.  It has been in continuous production for over one hundreds now.  Although certainly not an early CPI well, the Marshall Fee #5 bears state well serial number 5.  It's spud date is not included in the state database but it's status date is 10/19/1934.  Well serial numbers 6-9 are also located in the CPI Field.  Well Serial Number 503, Caddo Mineral Lands #5 is still status code 10 (producing) today.  It's spud date was 2/21/1918 and it is operated today by Three Sisters Petroleum, Inc. 

Although it is best to keep discussion threads focused on certain defined topics, I hope that members will share history (how about Reno Hill and drilling in a lake), some of the technical challenges of maintaining stripper wells and how the field impacts area economics to this day.  There are lots of good stories to tell.  One book I would recommend is  Early Louisiana And Arkansas Oil:  A Photographic History 1901-1946, by Kenny A. Franks and Paul F. Lambert.  Along with the CPI it includes the following fields:  Jennings, Monroe Gas Field, El Dorado, Smackover, Rodessa, Coastal LA and Offshore.

Permalink Reply by Curtis on June 10, 2012 at 5:53

Thank you Skip for all the information...

Permalink Reply by Skip Peel - Mineral Consultant on June 10, 2012 at 5:59

The Savage Brothers completed the first oil well, the No. 1 Auffenhauser, on March 28, 1906.  The very first wells drilled in 1904 and '05 were not productive or blew out owing to the field's high gas pressures.  Blow outs, fires and craters swallowing rigs and equipment would be common place in the early years of drilling.

Permalink Reply by Jay Reynolds on June 10, 2012 at 7:21

Thanks for starting this group Skip.

 

The CPI field has several key distinctions which in my mind differentiate it from other stripper well fields.  First is the multitude of formation types one can encounter behind a single well drilled to depth.  Those might include lenticular sands, massive fractured carbonated (Ann C), semi-consolidated sands that range from very high to high permeability. 

 

My nemisis is the Nacatoch B Sand where I have operated for about 7 years during my second incarnation in the business.  Although the oil we produce is considered "heavy" in other parts of the world with an API gravity of 19-22, the particular chemical makeup of the oil fetches the highest price of any oil produced in the state, irrespective of gravity.

 

When I speak around the country at EOR, SPE and Stripper Well Symposiums I might be the only presenter who is both a technology developer and an oil producer.  Being able to speak from the perspective of someone who has been forced to change the game from a technological perspective has made for some interesting conversations.

 

A few key takeaways lest I ramble on too long.

 

The Nacatoch in CPI has an atypically high percentage of the OOIP (Original Oil in Place) still remaining and though defined as "Stripper Wells" with the assumption that they are near the end of their useful life, leases that still have over 75% of the original oil remaining and many have produced 4-5 times the cumulative oil than was calculated to have ever been there in the first place so we know that the oil is horizontally mobile over time with many of these wells producing with a relatively flat decline curve for 50 years or more.

 

As far as stripper production goes, I often begin a presentation by saying, "Each of you knows more about your EOR projects than anybody else in the world and have gone to great lengths to select just the right chemistry and equipment.  If you will sit tight I will show you how to lower your labor costs for servicing, installing and relocating equipment by 99% (not a typo) and lower your lifting costs 50%.  How many more projects would you start and how many do you now have that you would operate longer if your costs were lowered that much?"

 

Another favorite is: "How much butt could you kick if you could time travel from 2012 back to 1930 and take with you everything you know about computers, aerospace, firearms, cellphones or medicine?  That's the scope of the opportunity we have, to mix and match, blend and adapt technologies to our needs and bring them into a market that is essentially producing wells as we did in the 1930's."

 

The problem we have in this lovely reservior is WATER.... we produce about 30X more water per bbl of oil than most other folks would even consider trying to produce. Key to changing the game is to change the way that fluids move towards the wellbore and that will provides LOTS if interesting discussion.

 

There are lots of $50,000 solutions to our $5,000 problems.  The challenge is to come up with $500 solutions!

 

JR

Permalink Reply by Skip Peel - Mineral Consultant on June 10, 2012 at 7:41

Jay, I considered a new group but decided to start out with a Caddo Pine Island, North Caddo Group discussion thread.  If there is sufficient interest I think a new group could be created focused on stripper wells and enhanced recovery techniques regardless of a specific location.  We may jump around a little here trying to cover all the bases but please continue with responses concerning the current challenges and the possibility of increased production through new technologies.  I am personally very interested in that part of the discussion.

At little more history for interested members:  There were numerous reports of wells blowing out and catching fire.  From Early Louisiana and Arkansas Oil, "One well near Oil City...burned out of control for five years before it was extinguished.  The crater was ninety feet deep and three hundred feet wide, and it was estimated that twenty-five million cubic feet of natural gas a day were consumed by the flames."

Permalink Reply by Skip Peel - Mineral Consultant on June 10, 2012 at 7:57

Another excerpt from Early Louisiana and Arkansas Oil, "Caddo, like other oil fields, held oil, gas, and water trapped in an underground layers of porous rock.  Gas, the lightest of the three, rose to the top of the trap, where it was prevented from escaping by an impervious layer of dome-shaped rock.  Consequently, the gas collected on the top and sides of the trap.  Below the natural gas the rock pores were filled with petroleum, often with oil and gas mixed in a solution.  Beneath the gas and oil, water accumulated at the bottom of the trap and held the gas and crude firmly against the impervious rock under great pressure.  Usually when the drilling bit penetrated the rock dome, the oil and gas gushed to the surface, to the delight of the oil men.  However, at Caddo the gas pressure was so strong that whenever the dome was penetrated, the first great rush would rupture the impervious rock trap and the softer rocks above it.  As a result, much to the dismay of oil men, the entire structure caved in, often within hours and often dragging the drilling rig and equipment into the chasm."

Permalink Reply by Jay Reynolds on June 10, 2012 at 8:08

Skip,

 

I have long ago transitioned from being "very interested" into "highly obsessed" with EOR that began with the drilling of the first ultra-short radius horizontals in Louisiana back in the mid 80's.  We were using a sledgehammer of a technology and one that was clearly not ready for Prime Time.

 

Starting in March of 2005 with the first State approved MEOR (Microbial Enhanced Oil Recovery) project just outside of Vivian, I have been working my way slowly through the flow chart of possible cost-effective solutions to change the Adverse Mobility Ratio (not knowing the readership, I am adding parenthetical remarks).  (AMR refers to the tendency of a reservoir to produce one kind of fluid preferentially over another. Basically, we have a very highly permeable sand with perm of up to 3 Darcies and an oil productive sand overlying a water producing part of the same reservior.  When a new well is put into production the fluid moves three dimensionally towards the pressure drop at the wellbore... think of milkshake being drawn into a straw...  With a new well the pressure drop at about 200 psi is plenty to mobilize our viscous oil towards the wellbore.

 

So think of the area around the wellbore as a beach ball cut in half and the lower half of that beachball is snug up against the cap of the B Sand.  The pressure gradient radiates outward and fluid moves in all directions that it can to get to the wellbore.  As the oil moves upward towards the wellbore it is replaced by the fluid that can take its place most easily which is the water underlying the oil sand. When this water reaches the wellbore it overwhelms the capacity of the pump to keep the well "pumped down" enough to creat the pressure drop necessary to mobilize the oil to the wellbore.  Install larger and larger pumps and the water channels simply widen out to accomodate the additional fluid flow that the pump can handle.

 

The produced water just "fingers" through the oil saturated sand leaving it unaffected for the most part except for the oil that "seeps" in horizontally and becomes our production.

 

So the key thing is to look at the variables and see which can be most cost effectively altered.  The main things that drive the AMR are effective wellbore diameter, rate of fluid removal, differential viscosity of oil vs water and differential density of oil vs water.  Working through that process has taken all of my time for the past few years but I have found out what works and am working through each stage of the proof of concept into to building the systems to do what I need to do.

 

JR

Permalink Reply by Skip Peel - Mineral Consultant on June 10, 2012 at 8:35

Good explanations, Jay.  It's always a challenge to put facts and concepts into wording that a majority of the members can understand  That can be more than difficult when dealing with the science of recovery.  I hope we draw some responses and questions from the members interested in the CPI and EOR.

Permalink Reply by Jay Reynolds on June 11, 2012 at 0:20

Skip,

 

Here is how it shakes out in sum.  If this level of detail is not interesting then I'll just sit back and watch for a while.

 

The Nacatoch Sands are massive, blanket sands which means that the oil bearing sand exhibits limited structure over the extent of its deposition.  The water underlying the B Sand has resulted in these wells rapidly coning to water over the course, usually, of a few months.  The tendency of the water to find the pressure drop that the wellbore represents is called Radial Matrix Coning where the water migrates to the wellbore through the reservior proper rather than through fractures.

 

Here's where it gets interesting.  There are any number of vendors that have solutions that are employed to good benefit in other parts of the world but one of the challenges that has never been economically addressed is radial matrix coning and this is where the opportunity presents for looking at the problem from a different perspective.

 

If you operate a Nacatoch lease and were to call a technology vendor that provides solutions in other areas they would probably recommend what works best in other places without digging too deeply into the particulars of Pine Island.  The "normal" solution for mobilizing heavy oil to a producing well is to prepare a mixture of polymer (thickens the water) and surfactant (special "soaps" to lower the interfacial tension (IFT), the force that is telling each particle of oil, water and gas that they have to be of a particular size and that they have to remain separated from each other.  Lowering the IFT has the effect of reducing the amount of mechanical energy required to move fluids through a porous media - the reservior.

 

Setting up a polymer injection program would require high pressure plumbing and pumps and the conversion of a large number, perhaps 1 out of 5, of the current production wells into injection wells.  The idea is that injecting this thicker mixture, which more closely resembles oil in its viscosity, will push oil from the point of injection towards the producing wells through the formation of an oil bank.

 

That was what was suggested to me so I tried it in a pilot project that was only modestly successful.  Then I looked at the assumptions that the technology provider was operating under and key was that nearly all of these projects were being undertaken where well spacing was 1 producing well/10 acres or so.  Spacing in CPI where I operate may be as dense as 34 wells on 5 acres or one well every 75'.

 

Assuming that the usual injection method worked there would still be the challenge, even if one could overcome the expense, of leaving oil between the injector and the producers bypasses through "fingering", where the injected fluid bypasses the oil.  When this happens another whole set of problems surfaces to be solved under the description of "Conformance Control" and the volumes of fluid to be injected to remediate that condition are huge.

 

So looking at what I had to work with it occured to me that Radial Matrix Coning, the tendency of the water to bypass the oil enroute to the wellbore, was exactly the same as "fingering" only it was operating vertically instead of horizontally.  In other words, I didn't need to go to the expense to set up a "flood" because nature had already given me a natural waterflood. The good news was that it was operating vertically - tending to try to push the oil in a direction that Mother Nature wanted it to move, vertically, instead of the case with a man made flood which would try to move the oil horizontally, in a direction not favored by nature.

 

In sum, the notion now is to capitalize on what has been a detriment, having what is essentially an "already installed" waterflood, and lots of wellbores.  If water breaks through again at these wells it is much simpler to remediate the problem at the wellbore than trying to affect the movement of fluids over a large volumetric area between injectors and producers.  The first trick has been to learn how to economically shut off the water using a low tech approach.

 

JR

Permalink Reply by dbob on June 11, 2012 at 1:21

JR -

Very interesting, even for those of us who don't really understand.  Two questions - what is the typical chloride concentration in the water?   And what is its typical use/disposal method after production?

Permalink Reply by Jay Reynolds on June 11, 2012 at 9:20

The total dissolved solids, mostly chlorides, yields a specific gravity of 1.105 for our water vs 0.96 specific gravity for our oil, hence the inefficiencies in oil/water separation.  Our SWD wells are typically completed below the production zone in the Nacatoch C and will take about all the water you can give them on a vacuum.  SWD pumps are used mostly to overcome flow line losses to the SWD wells.

 

If you have a use for it, aside from setting up Bubba's Brine Shrimp Farm, I'd sure be interested to know. 

 

JR

Permalink Reply by Jay Reynolds on June 11, 2012 at 10:40

Correction: 1.015 sg for produced H20

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