What’s new in Polymer Technology?New tools to help get the most oil & gas from your wells.
Polymer Services, LLC • Expertise: Design, field application, and evaluation of polymer gel treatments since 1989. • Locally owned and operated. Management and employees are all natives of the immediate area. • Services: Assistance with candidate selection and treatment design, polymer products, laboratory, field implementation equipment and experienced crews and project supervision. • Headquarters and Field Offices: Plainville, Kansas, USA.
General Overview • In recent years, POLYMER SERVICES has pumped a total of 2,005,805 barrels of gel in 782 treatments. (as of March 1, 2010) Approximately 1500 earlier treatments were pumped (1989-2002) using older technologies. • It is estimated the treatments have yielded at least 3,500,000 barrels of additional oil to date. • Average incremental oil production per well is 4475 bbls, including unsuccessful treatments. • Indicates a gross value of at least $175,000,000.00 (based on $50/bbl oil)
What is Polymer Gel? • The original process developed(1960’s), by Phillips Petroleum Company as a way to reduce water production in the Bemis-Shutts field of Kansas (chrome/redox system) • The first polymer treatment ever pumped anywhere in the world, was by Phillips Petroleum Company in the Bemis-Shutts Field in Ellis County, Kansas in the late 1960s, under a great deal of secrecy. • Today’s gels are created when polymer is mixed in water and cross linked with a trivalent chromium ion. • The technology has evolved from early biopolymers to modern synthetic gels which are now used worldwide.
Polymer and crosslinker are mixed on the surface as opposed to previous systems that (hopefully) mixed in the reservoir. This was known as in-situ gellation. • Gel Strength is a function of polymer concentration. • Gels having viscosity slightly greater than fresh water to that of rubber can be created in virtually any water, at temperatures up to 270 F, in high TDS, H2S and CO² environments. Continued:
Used to shut off unwanted water in producing oil and gas wells, and to improve conformance at water/CO² injection wells. • Considered to be permanent after placement. • Special equipment is normally required to properly blend and pump polymer gels.
Modern Chemistry Options • The current system used is a modified tri-chrome system known as WATERBLOCK, based on technology originally developed by Phillips Petroleum Company, and is largely responsible for the current high success rate in the Arbuckle dolomite and other formations in Kansas. • The key to current successes is the use of this chromium III gel system as opposed to older crosslinking technologies, which were less robust or forgiving than the current system.
What are the benefits? • This chemistry was originally developed for stable gels in deeper hotter wells than we normally find in Kansas. It was also intended for “hostile” environments, which include much higher salinities, high H2S counts, high TDS brines, etc. Polymer Services has modified this chemistry to also be very effective in shallow low temperature wells. • A benefit to this chemistry is greater final gel strength and fewer problems with polymer production when the well is turned back on, and greater long term gel stability in our “relatively tame” wells.
What else do we do differently? • POLYMER SERVICES uses “Liquid Polymer” which is custom blended as a “pre-wetted” solution, instead of the dry powder used in other common processes. • Pre-wetted solution means each individual polymer grain is pre-hydrated in it’s own water droplet, then suspended in a mineral oil solution. This allows the polymer to hydrate much more rapidly for a more complete and effective crosslink, even at lower temperatures.
How does this help? • A pre-wetted polymer solution is much easier to fully hydrate and completely dissolve in all types, hardness and temperatures of mix water. • Better dissolution means more complete cross-linking, better final gel strength and stability, and no produced polymer when the well is re-started.
How have Polymer jobs today improved compared to what has been done in the past? • Today’s gels are more stable in a wide range of pH, high temperature, high H²S, salinity and high TDS environments. • Today’s treatments are much larger in volume, which allows for deeper penetration into the reservoir, thus yielding significantly greater amounts of incremental oil and longer effective treatment life.
Well candidate selection criteria • Significant remaining mobile hydrocarbons in place (cumulative production history is usually a good indication). • Wells producing at or near their economic limit due to costs associated with excessive water production. • High water disposal and/or lifting costs. • Producers in natural waterdrive reservoirs. Continued:
Well candidate selection criteria • Producers in water floods are treatable, but recommend treating injectors. • Sometimes both the injection well and offending producers are treated for optimum results. • Better chance of increasing oil production when treating wells that have high producing fluid levels. • High permeability contrast between oil and water saturated rock • Vuggy and/or naturally fractured reservoir.
Example of High Permeability contrast • Arbuckle core recovered in Rooks County, Kansas during a deepening operation on a workover rig.
Example of naturally fractured Arbuckle dolomite • Another view of the workover core, showing a combination of vugs and fractures.
Key Factors in designing gel treatments • The type of gel polymer/crosslinker and concentration • Treatment volume • Treating procedure
Treatment Design Information • Wellbore schematic/data • Tubing size & depth, casing size & depth, perforated/openhole depths, beam or submersible pump, etc. • Porosity/electric logs • Core reports • Oil and Water production history • Fluid pump-in data from acid jobs or other work • Cumulative recovery map • Structure/isopach map • Oil price and water handling cost
Sizing the Treatment • DISTANCE… • Radial or linear flow calculation • 50-1000 Bbls. Per porosity-foot (depends on well productivity) • VOLUME… • Estimate daily capacity of well to produce fluid at maximum draw-down, then use that volume to determine minimum gel treatment volume • Need static and producing FL, and producing rate(s)
Before Pumping the Job • Ensure that the wellbore is clean, sand pump or otherwise clean out well to original TD. • An AGGRESSIVE acid cleanup treatment has proven to be very effective (1500-3000 gallons 15% NEFE, pump away with water at high rate). • Establish a maximum treating pressure. Use calculated frac gradient for field or run step-rate test if necessary. Continued:
Before Pumping the Job • Select an acceptable source of water that will be used to blend and pump the treatment (fresh. Kcl, or clean produced water which has been tested for polymer compatibility prior to treatment). • Select a polymer-compatible biocide for mix water (mix at concentration recommended by the supplier). • Set packer on tubing to isolate zone to be treated.
Mississippian DolomiteHodgeman County, Kansas • Pre-treatment oil rate was 5 BOPD, 870 BWPD. • Treatment was 3280 bbl WATER-BLOCK 247, pumped July, 2007. • Well averaged 50 BOPD, 275 BWPD during first 30 days after treatment. • Cumulative production to date: 4042 incremental barrels, • Treatment cost was $40,496.00.
Mississippi DolomiteHodgeman County, Kansas • Well was making 24 BOPD, 3400 BWPD prior to treatment. • Treatment was 7520 bbl WATER-BLOCK 247, pumped October, 2007. • Peak production 1st month after treatment: 64 BOPD, 340 BWPD. • Current production 27 BOPD, 363 BWPD • Incremental oil to date: 4200bbls
Miller #2Hodgeman County, Kansas • Mississippian (Osage) well was making 6 BOPD, >600 BWPD prior to treatment. • 3120 bbl WaterBlock-247 pumped beginning 12/10-2007. • IP after treatment was 67 BOPD, 53 BWPD.
Miller #2 (continued) • Current production reported to be +/- 40 BOPD, 80 BWPD, not pumped off. • Estimated incremental oil to date is 3060 bbl. • Total workover payout occurred in approximately 29 days.
White Eagle Resources • On June 2, 2003, a 10 well project was commenced In the Bemis-Shutts field for White Eagle Resources. • Prior to treatment, the subject wells produced a combined average of 47 BOPD and 12,000 BWPD.
Overview of the White Eagle treatments • Treatment sizes ranged from 1100 barrels to 5100 barrels of gel, depending on the pressure response during treatment. • A total of 38,320 barrels of gel were pumped on the 10 well project. • Pressure response ranged from vacuum to a maximum of 750 psi surface pressure.
White Eagle Results • Individual well productions after treatment ranged from 16 BOPD to 145 BOPD, on an average of no more than 150 BPD total fluid. • Peak production occurred in early October, at just over 500 BOPD. • Current production is 180-200 BOPD.
Economic Value • White Eagle Resources estimated the Net Present Reserve value of the wells has increased from approximately $1,000,000 to approximately $4,000,000, as a result of the treatments. • Incremental oil production is estimated to be at least 81,000 barrels • All estimations are based on totals as of January 2006
After the first 10 well study • White Eagle resources did an additional 14 Waterblock 247 treatments • Between October of 2003 and April of 2006 an additional 47,975bbls of Waterblock 247 was pumped • Average size of treatment was 3960 bbls
Property sold in 2006 • New operator has continued the successful program, which is now ongoing on a continuous basis. • Has pumped an additional 44 treatments since 2006, using our exclusive WATERBLOCK-247 polymer gel system.(54 treatments since project inception • Average treatment has been in excess of 3650 barrels.
With a combined total of 246,835 bbls of Waterblock 247 polymer pumped • Treatments resulted in additional 215,946 bbls of oil (as of October 2009) • Increase in revenue (based on $50.00 bbl) $10,797,300.00 • Combined total production since project inception is now 671,571 bbls of oil
An Example of a Successful Gas Well Treatment in the Viola Limestone formationPratt County, Ks • Treatment was 150 bbl WATER-BLOCK 247 • Production before treatment: • 0 MCF, 300 BWPD • Initial production after treatment: • 85 MCF, 0 BWPD • Current production: • 247 MCF, 0 BWPD
Viola limestoneComanche County, Ks • Treatment was 425 bbl WATER-BLOCK 247 • Production before treatment: • 50 mcf gas, 900+ BWPD • Initial production: • 450 mcf gas, 250 BWPD .
Snyderville sandBarber County, Kansas • Production prior to treatment:600/BWPD, 100 mcf gas (declining) • Treatment was 75bbl HDLV polymer with a maximum shut in of 5 days • Initial Production after treatment:250/mcf and 200 BWPD. • The water depleted to 52 BWPD and the gas increased to 600mcf one month after treatment. • 18 months after treatment production stabilized at 300mcf with minimal water production.
Polymer Water Shutoff Treatments • Problem: • Excessive water production (typical candidate well producing 500-5000 BWPD) • .5 thru 2% Oil cut • High producing fluid levels • High electricity costs ranging from $600 to $6000/month per well • Wells shut in due to lack of disposal capacity / high lifting costs Continued:
Polymer Water Shutoff Treatments • Solution: • Polymer water shut-off get treatments are designed & pumped based on candidate selection criteria, available well data and experience with similar wells in the area • Treatment size have ranged from 75 BBL to over 10,000 BBL Waterblock 247, depending on individual well conditions Continued:
Polymer Water Shutoff Treatments • Result: • Average water production per well is reduced 75-90% • Daily oil rate typically increases from 50% to more than 60 times the original production • Incremental oil production ranges from 800 to 5400 barrel of oil per month have been reported. • Electricity savings ranges from $500 to $3500/month per well
Conclusions • Much has been learned about proper candidate selection, preparation of the well for treatment, and optimizing treatment designs, based on a wide cross-section of treatments and responses in the field. • This knowledge has led to much greater success rates and incremental oil recoveries from polymer gel applications in a wide variety of reservoirs.
Conclusions (continued) • Improved polymer gel technology has vastly improved results in all areas • The improved results can largely be attributed to the following changes which have occurred in the past few years: • A transition from older cross-linking technology to the current chromium III gel technology, which has become the standard Continued: