The California DOGGR did not deliver a permit for the CGR VPC #71X-33 well. As a result, the well could not be drilled.
In late October 2011, Compass Global Resources finally proposed the CGR VPC #56-14 well for which it was granted a drilling permit. Arbol Resources, Inc decided to go non-consent on this well considering it could be partially depleted from neighbouring producing wells.
During January 2012, the operator was negotiating with Underground Energy, Inc. a possible farm-out over the West Gosford area. Apparently, nothing was agreed.
In May 2012, the company MK California, LLC proposed to the operator a purchase of all interests in the West Gosford, Canfield Ranch and South Strand areas.
In June 2012, Arbol Resources, Inc. received a letter of intent which was signed and returned to MK California, LLC on July 2nd, 2012.
In September, ARI received the purchase and sale agreement but at the end of the month, the deal was still not closed although MKCA, LLC reiterated its interest for it.
Finally the sale was concluded in February 2013 and Arbol collected its funds.


On November 23rd, 2011, Underground Energy, Inc. closed the purchase of Panther Energy Company’s all right, title and interests in the Challenger prospect. The Effective Date of the assignment was October 1, 2011. Underground Energy, Inc. took over the operating.
The new operator proposed to recomplete the Wil E. Coyote #1-33 at the Zilch sands level and Arbol Resources, Inc. agreed with their proposal.
In May 2012, the ”Sandy Mush” lease, where the Wil E. Coyote #1-33 well is located, expired and the lease was not renewed, due to the fact that the well was not producing anymore.


At the end of February 2012, TGS Industries, Inc. began the acquisition of a 50 square miles 3D seismic over the Rose Valley acreage. In April 2012 the acquisition was completed and in May 2012 the processing. In September, the seismic interpretation already evidenced two structures that will be drilled before year end.
In October 2012, Ares Energy, Ltd proposed the drilling of two structures named SW Leesburgh and North Bunyan. In November 2012 the operator drilled Lewis 14 #7 well and in December the Fisher 18 #10.
At the end of December, the Lewis 14 #7 well was completed in the Lansing formation. In mid-January 2013, the well was tied-in and produced approximately 35 barrels of oil per day.
In January 2013, the Fisher 18 #10 well was completed also in the Lansing formation but rapidly proved to be uneconomic.
In January 2014, the operator drilled the Fisher Farms 9 #11 well and the McCandless 15 #3 well. The drill stem test of the Fisher Farms 9 11 well was deceiving and ARI decided not to participate in the completion.
In February 2014, the McCandless 15 #3 well was completed in the Simpson sands and production started a month later with an initial rate of 65 barrels of oil per day.
In June 2014, the McCandless 15 #3 well was recompleted in the Viola formation. A month later, the well was not producing anymore. It was then decided to put it back into production at the Simpson sand level. At the beginning of August 2014, the well produced an average of 80 barrels of oil per day.
In March 2016, Ares Energy, Ltd proposed to sell the property and ARI agreed. The sale was successfully completed two months later.


The Well #13-13A well was drilled in September/October 2011. The Cherokee A & B intervals were cored. The well reached a total vertical depth of 4,385’ (1,336.5 m) and unfortunately, the sand reservoirs were water saturated. However, the operator attempted to perforate and acidize the Mississippian and the Cherokee sand levels. This completion was unsuccessful and the well was plugged and abandoned.
The Pranger #7-4 and Georg #34-11 wells were drilled back to back.
Both wells encountered water -bearing reservoirs that led the operator to plug and abandon the wells.
In November 2011, the Mantz #9-3 well was drilled and reached a total vertical depth of 4,485’ (1,367 m). Good oil shows were encountered at the Mississippian level. Four drill stem tests were achieved, three at the Cherokee sand level and one at the Mississippian level. The completion was attempted but only mud with oil traces were observed. In mid-January 2012, the well was put in production and produced approximately 200 barrels of oil to March 2012 before it produced only water. Thus the well was plugged and abandoned.
Following the last four unsuccessful wells the operator decided to present the prospect at the North American Prospect Exposition held in Houston in February.
In March 2012, Ares Energy, Ltd received a purchase offer from Encana Oil & Gas, Inc. which was agreed by all the partners of this project. The sale closed on April 1st, 2012.


Following the acquisition of this prospect in 2007, the various agreements were finally signed in October 2008.
In 2009-2010, Cheyenne Petroleum Company drilled the first horizontal well, the Irvin Family #1 pilot well, with two laterals one in the Sligo formation and another one in the Eagle Ford formation. All completion attempts were achieved in the Sligo/James Lime, Pearsall and Eagle Ford formations. Unfortunately, the well could not be completed correctly in the Eagle Ford horizontal leg because of mechanical problems.
From July to October 2010, Cheyenne Petroleum Company drilled the Irvin Family #2H well which was fractured and completed in the Eagle Ford formation. Then the operator drilled the Irvin Family #3H well. In December 2010 and January 2011, this well was completed in the Pearsall formation.
From January 2011 through the beginning of 2012, the operator drilled five horizontal wells with lateral in the Pearsall formation and thirteen horizontal wells with laterals in the Eagle Ford formation. Production was delayed due to limited infrastructure and pipeline capacity. Also the operator had to install treatment facilities to remove the H2S associated with the produced gas. Therefore, during this time, only four wells were producing.
During the additional time in which experience was gained, the operator drilled longer laterals and enhanced its fracturation technology by adjusting the number of stages. Production tie-in were also improved.
As a result, at the end of 2012, thirty wells were producing nearly 200 million cubic feet of gas and 115 000 barrels of oil.
In the middle of 2013 year, the operator started to install electric submersible pumps in order to increase the oil production and then reduce the exploitation costs.
At the end of 2013, fifty-six wells were producing approximately 260 million cubic feet of gas and 268 000 barrels of oil.
Another six wells were put in production through July 2014.
Arbol Resources, Inc seized the opportunity that it was presented to sell all its interests in this project. The sale was concluded on October 14th, 2014.


The Clark & Sain #11 well ceased to produce and was plugged and abandoned in 2012.
In July 2014, a workover was successfully completed in the Ball Ranch #3 salt water disposal well.
In September 2014, the Clark & Sain #3, #17 and Ball Ranch #7 wells were acid treated to remove the scale deposit that was found in those wells.
In June 2015, the Clark & Sain #5, #10 and Ball Ranch #3 wells were shut-in as they became uneconomic. In July 2015, the French State #1 and #4 wells were also shut-in for the same reasons.
In September 2015, workovers were done in the Clark & Sain #3, #8 and Ball Ranch #20 wells in an effort to increase their production.
In January 2016, the French State #2 well was shut-in as it became uneconomic.


In August 2011, the BS Harrison #2 well entered communication at the Rodessa formation level with a nearby injection well. Thus it was decided to plug and abandon the well.


In February 2012, Plantation Petroleum Company, LLC approached the operator with an offer to purchase portion or all of his interests in the property. Each partner who wanted it also received a purchase offer of his interests. Arbol Resources, Inc. decided to sell its stake in the project and in March 2012, the sale was completed.


In September 2011, Arbol Resources, Inc. agreed to participate in the drilling of one of the last two proposed wells and disagreed to participate in a new lease acquisition in Lipscomb County.
The horizontal Reckless 1028 #1HM well was drilled in October/November and reached a total vertical depth of 7,504 feet (2,287.2 m) and a total measured depth of 11,975 feet (3,650 m). In December, the well was put in production after a 17-stage frac was performed in the Hepler sands. The well produced 33.3 million cubic feet of gas and 17,846 barrels of oil through August 2012.
In January/February 2012, the Lesa Lynette 1027 #3HM was drilled and because of numerous mud motor failures was sidetracked three times. It finally reached a total vertical depth of 7,464.90 feet (2,275.3 m) and a total measured depth of 11,972 feet (3,649.07 m). It was put in production after a 17-stage frac was performed in the Marmaton formation.
At the same time, the horizontal Chubbs 996 #4HM well was drilled to a total vertical depth of 7,584.8 feet (2,311.85 m) and a total measured depth of 12,108 feet (3,690.52 m). In March 2012, it was also fractured in the Hepler formation and put in production.
The same month, the horizontal Sam 938 #3HM was drilled, sidetracked and reached a total vertical depth of 7,493.95 feet (2,284.16 m) and a total measured depth of 10,728 feet (3,270 m). In May 2012, it was put in production after a 15-stage frac was performed in the Hepler sands.
In March/April 2012, the horizontal Dooney 997 #1HM well was drilled and reached a total vertical depth of 7,577.6 feet (2,309.65 m) and a total measured depth of 11,842 feet (3,609.45 m). In May 2012, it was completed with a 17-stage frac and put in production.
The horizontal Buddy 998 #5HM well, drilled also in March/April, reached a total vertical depth of 7,501.8 feet (2,286.55 m) and a total measured depth of 11,844 feet (3,610.05 m). A 17-stage frac was also performed in the Hepler formation and the well was put in production in May 2012.
In March 2012, Arbol Resources, Inc. received a purchase offer for all its interests in the project from the operator. Although ARI made two counter offers the operator did not respond.
In September October 2012, the Sam 938 #4HM well was drilled and reached a total vertical depth of 7,529.00 feet (2,294.84 m) and a total measured depth of 10,792 feet (3,289.40 m). In November 2012, it was completed in the Marmaton formation with a 15-stages frac performed and put in production at the end of the month. The first 12 days the well produced 4,000 barrels of oil and 6,684 thousand of cubic feet of gas.
In January 2013, workover operations were performed on the Buddy 998 #5HM well, in February 2013 on the Stormy 1084 #2HM well, in March 2013 on the Sam 938 #4HM well and the Blackie 1083 #3HM well, in May 2013 on the Loesch 1118 #3HM well and in July 2013 on the Sam 938 #3HM well.
In July 2013, the property was sold by Holmes Exploration, LLC to Midstates Petroleum Company, LLC who became the new operator.
In January 2014 a workover took place on the Reckless 1028 #3HM well.
In April 2014 rather than to participate in the drilling of two new development wells in section 1084 ARI decided to sell its interests in these wells to the operator.
In May 2016, Midstates Petroleum Company, Inc. and Midstates Petroleum, LLC have filed for voluntary bankruptcy and will reorganize under a prearranged financial restructuring.


In October 2011, one partner of the Booker 3D Project, Ryan Petroleum, LLC, proposed all partners to drill a well in the northwest corner of the Booker 3D AMI to evidence the presence of the Morrow A & B sands in this area. Arbol Resources, Inc. decided to participate under the same terms as in the Booker 3D project whereas the current operator declined the participation. Therefore Ryan Petroleum, LLC had to find an operating company which is Gunn Oil Company.
In March 2012, the Duke WB #1 well was drilled to a total vertical depth of 8,380 feet (2,554.22 m). Unfortunately the Upper Morrow sands were not present and the well was plugged and abandoned.
After an extensive reinterpretation of the seismic data had been done, one partner of this prospect, Brown & Borelli, Inc. thought that the Duke WB #1 wellbore did not reach the seismic anomaly. It then proposed to check the well deviation and then proposed to sidetrack the well should their thoughts be confirmed. Arbol Resources, Inc. declined to participate in this proposal.
In March April 2013, the Duke WB #1 well was sidetracked and as many mechanical problems occurred, the well was finally plugged and abandoned.
In May 2013 ARI did not participate in the proposed reprocessing and reinterpretation of the remaining 3D seismic.


Arbol Resources, Inc. decided to shut-in the Briggs #1, #2, #3 wells on June 30th, 2011 as the production became uneconomical at current gas prices.
These wells were plugged and abandoned before 2011 year end.
Consequently, the corresponding leases and the Sallie Jane Anderson lease were officially released on February 29th, 2012.
In 2011/2012, Arbol Resources, Inc was in negotiation to acquire additional leases in the same area. At the end of September 2012, the acquisition was finalized.
Arbol Resources, Inc successfully marketed Cotton Valley gas and Buda/Georgetown oil prospects.
In May 2016, ARI signed a lease acquisition and development agreement with Fortis Oil and Gas, LLC while remaining the operator.
In October 2016, the Anderson #2 well was drilled and reached a total vertical depth of 4,766.00 feet (1,452.67 m). It encountered numerous oil and gas shows especially in the Buda/Georgetown formation. In December 2016, the well was fractured in the Buda formation. After the flowback results and many other considerations, it was decided to fracture a second time the Buda formation which was done at the end of February 2017. In March 2017, while the well was producing small quantities of gas, it was fractured in the Pecan Gap formation. It then produced some oil and gas.
In February 2017, the existing Wiese-Gibson #1 well was renamed the Anderson #1 well. The well was fractured and recompleted in the Pecan Gap formation. While running a temperature log, paraffin deposits were encountered. An electric pump and a heater treater were both installed allowing the well to produce 225 barrels of oil and some gas in March 2017.
In May 2017, the Anderson #2 well stopped producing due to pump issues and it was also found paraffin deposits. The well had to be treated with paraffin inhibitor injections and a heater treater also had to be installed in order to allow the well to produce the Pecan Gap oil.
Mid-June 2017, the Anderson #1 well stopped producing and the well was temporarily shut-in. The goal is to find the best solution to apply to the Anderson #2 well to avoid paraffin deposits and produce the Pecan Gap oil without interruption. Then the solution will be applied to the Anderson #1 well and it will again be put online.
In September 2017, the Calvert Farms #1 well, a Pecan Gap development well, was drilled. The Pecan Gap and Wolf City sand formations were diamond cored to best evaluate the production potential. The cores are being studied.


At the end of September 2011, a rig was towed and installed over the State Tract 127 #1 well and South Bay Resources began the completion. The Bol Mex sands were isolated, perforated and fractured. Although green oil traces were observed before the frac stimulation, the swabbing reports only indicated significant water returns. Unfortunately the Bol Mex formation was water bearing. The well was then plugged and abandoned before the end of 2011.
As operator of the Keller Bay’s production facilities and the Matagorda pipeline, Arbol Resources, Inc. had to plug and abandon the Esenjay State Tract 77 #3 well. This was completed in December 2011. On July 25th, 2012 a physical inspection of the Production facilities and the Matagorda Bay’s pipeline had been conducted by the Railroad Commission. Following this visit, Arbol had to fulfil various RRC security requirements such as a pressure test in the ST150-6” pipeline which must be done before any service activation (pipeline currently shut-in) and an underwater physical inspection which was done before March 10th, 2013.
Arbol, et al. believe some oil & gas were left over in the ST 150 #2 wellbore and therefore in the entire northern block of the main fault (30 Bcf of gas & 1 MMBO of oil). For this reason, Arbol is promoting the prospect to a third party interested operator in order to develop these remaining reserves by recompleting the ST 150 #2 wellbore and by drilling two new wells.
Arbol felt that a reprocessing of the existing and additional seismic would help, according the result, either to promote the project or disregard the project and stop its promotion.
In February 2013, 139.2 square miles were acquired from SEI. In September 2013 the reprocessing was completed by Allan Long. Allan’s work provided a better analysis of AVO anomalies observed in the Frio formation and also in the Miocene formation. The goal was to interpret and identify potential drilling prospects to participate to the auction of lands of the GLO in April 2014. As the seismic interpretation results did not demonstrate additional oil and gas accumulation in the State Tract 150, Arbol decided to allow all leases to expire. From August to December 2014, field work was done in order to abandon the pipeline.


Burk Royalty, Inc finally found a purchaser for its interests; it’s Enervest, Ltd who was also a partner in this project.
All partners sold their interests, including Arbol Resources, Inc., who owned a 5% WI. The sale’s effective date was February 15th, 2012.


During the first quarter 2012, Texican Oil learned that our gas purchaser had difficulties with its only client Drummond Ltd that wanted to renegotiate the gas price on the pretext of various delays of the project. Texican Oil had to terminate officially the gas sale contract with its purchaser who could not fulfil his obligations.
In spite of this situation, Texican Oil decided to import the gas treatment plant and this was done in April/May 2012. As for the pipeline, it was decided to keep it in storage in Houston for the time being.
The installation of the gas treatment plant started in June 2012.
Meanwhile Texican Oil was dealing with gas distributors to find a new purchaser. At the end of the year Texican signed a gas sale contract with Gases del Caribe S.A. E.S.P. who will build a pipeline to tie-in the Maracas treatment gas plant. Gases del Caribe S. A. S E.S.P. will also build a measuring station that will control the gas quality and meter the amount of energy sold.
In 2013, Texican Oil’s pipeline, still in storage in Houston, was re-acquired by NOV FGS, who purchased Fiberspar in October 2012.
Texican pursued the installation of the gas treatment plant and at the end of October 2014 tied-in the Compae #1 well to it. In November 2014 the gas treatment plant was ready waiting to be tie-in to the Gases del Caribe S.A. E.S.P.’s pipeline. From March to October 2014 Gases del Caribe S.A. E.S.P. built the gas measuring station. The installation of GdC’s pipeline experienced some delays and the first producing test finally began in November 2015. Necessary checkings and adjustments were achieved and the stabilized production occurred in late January 2016.
At first, it was decided to produce the gas only from the Compae #1 well. The Compae #2 well will be tied-in and put into production at a later date.
Texican is studying the various cogeneration solutions using the present burned permeate gas in order to lower its atmospheric emissions.
Texican is looking for partners interested in the exploration and development of the Lagunitas oil. The project of a seismic acquisition and an horizontal well are still relevant.