October 15, 2016

Mr. Hans R. F. Helland

Inland Ocean, Inc.

P. O. Box 6949

San Antonio, TX 78209

RE:Fracture Treatment Design– Sarah #2, Yegua 8700’ Sands

Dear Hans:

Attached is the frac pack treatment designfor the Yegua 8700’ sands in the Saran #2 well, Wharton County, TX. This treatment is based on pumping down 4-1/2”, 15.1 lb/ft casing at 24 BPM. The fluid to be used during this treatment is a 30# guar base gel with delayed borate crosslinker and the proppant is 87,000 lbs. of 20/40 Super HS or equivalent4% resin-coated sand.

The perforations for this treatment are 8,704 – 8,716’, 1 SPF, 60 phasing (16 total perfs). The perforation entry hole size should be 0.32”. If the perf diameter is larger, then it will be necessary to reduce the number of perforations, so that we can ensure that we treat all perforations.

The FRACPRO PT model results for this treatment design indicate that the fracture half-length is 204’. The upper fracture height is 121’ (8,589’), while the lower fracture height is 94’ (8,804’).

We recommend that a fluid efficiency test (FET) with a step rate test at the end be conducted prior to the treatment to allow the pad size to be optimized and to check for tortuosity or excess friction. There should also be 5,000 lbs. of 100-mesh sand on location in the event it is necessary pump sand slugs. The 100-mesh sand should be available to return to the service company if it is not utilized. We also recommend that there be 40#/1000 gals. of biodegradable fluid loss additive and an additional frac tank of water and chemicals to gel the tank on location if the FET indicates it is required.

We also recommend that 50% standby horsepower (HHP) and a standby blender be rigged up and available to bring immediately to treatment rate and pressure in the event a mechanical failure occurs during the treatment. In addition, we recommend that intense quality control be performed on the treatment and that the well be flowed back immediately using the forced closure technique. The total volume of fluid to be flowed back should at least 2 – 3 times the casing volume or until the proppant cleans up.

We at Ely and Associates appreciate the opportunity to work with you on Inland Ocean’s stimulation program and look forward to continuing our excellent working relationship.

Sincerely,

Steven L. Fowler

Inland Ocean, Inc.

Design: Sarah #2, Yegua 8700’ Sands

Wharton County, TX

Perfs: 8,704 – 8,716’; 12 Total Perfs; 0.32” diameter

Stage / Fluid
Type / Fluid
Volume
(gals) / Proppant
Concentration
(ppg) / Stage
Proppant
(lbs) / Injection
Rate
(bpm)
Load/ Step Rate / 20# Linear Gel / 5,500 / -- / -- / 0-24
FET / 20# Linear Gel / 5,000 / -- / -- / 24
Shut down, obtain ISIP, and monitor well to fracture closure and determine fluid efficiency. Redesign pad volume.
Prepad / 30# Linear Gel / 2,000 / -- / -- / 24
Pad / 30# X-Link / 5,000 / -- / -- / 24
0.5 ppg / 2,000 / 0.5 / 1,000 / 24
1 ppg / " / 2,000 / 1.0 / 2,000 / 24
2 ppg / " / 2,000 / 2.0 / 4,000 / 24
4 ppg / " / 2,500 / 4.0 / 10,000 / 24
5 ppg / " / 4,000 / 5.0 / 20,000 / 24
6 ppg / " / 5,000 / 6.0 / 30,000 / 24
8 ppg / " / 2,500 / 8.0 / 20,000 / 24
Flush / 20# Linear Gel / 2 bbls. above top perf / 24

TOTALS:20#/30# Linear gel -17,614 gals. plus tank bottoms

30# X-Link -25,000 gals. plus tank bottoms

20/40 Super HS or equivalent 4% RC sand - 87,000 lbs

100 Mesh Sand - 5,000 lbs. (if sand slugs necessary, prefer for sand to be returned if not utilized)

DESIGN/FLUID CRITERIA:

  1. Design pump rate – 24 bpm.
  2. Maximum pump rate – 34 bpm.
  3. Average treating pressure – 6,000 psi.
  4. HHP required – 3,529HHP plus 50% standby.
  5. Fluid – 30#/1000 gals. of guar base gel with delayed Borate crosslinker.
  6. All fluids should be Continuous mixed.
  7. Based on pumping down 4-1/2”, 15.1 lb/ft casing.

ADDITIVES:

  1. Delayed Borate crosslinker.
  2. Buffer with true buffering capacity.
  3. Caustic as required for high pH.
  4. Surface crosslink borate for early viscosity.
  5. 1 gal/1000 gals. Surfactant/non-emulsifier.
  6. Biocide added to tanks as they are filled.
  7. 4% KCl required for clay control (no KCl substitute).
  8. Delayed release breakers will be added based on the results of break tests conducted at static bottom-hole temperature (215F). Do not use persulfate or encapsulated persulfate breakers for the crosslink gel breakers.
  9. Have 35% excess chemicals available to prepare for results of FET.
  10. Have 3 - 500 barrel tanks of 4% KCL water on location.
  11. Have 2,000 pounds of starch fluid loss additive available if required based on results of the FET.

ADDITIONAL EQUIPMENT:

  1. 2 in-line densitometers (one near the wellhead).
  2. Model 35 and 50 viscometers, pH measurement, sand sieves, and associated equipment to perform QC on location. Sand sieves on all compartments and water analysis on all tanks.
  3. 50% Standby horsepower.
  4. Pressure relief valve on the casing and kick-outs or pop-off required on down hole

pumps.

Service company to supply viscosity vs. time profile of submitted frac fluid at 215F. Fluid should maintain viscosity of 350 cps at 40 sec –1 witha B5Bob for job duration. Pilot tests should be conducted with frac water and chemicals to be used on the actual treatment. The well will be flowed back using the forced closure technique.

We also require a break test showing complete breakdown in 24-36 hours at 2-3 cps at ambient temperature.