Daqing Oil Field ASP Projects, Daqing, China

Polymer flood was successful in Daqing and its incremental recovery over water flood is more than 12% OOIP. Up to 1998, Daqing produced 8.16 million tons of the crude oil by polymer flooding. Micelle flooding was then field tested and concluded technically successful but not economical. In order to lower the cost of chemical flooding, Alkaline Surfactant Polymer flooding was studied in the laboratory and tested in the field. Both numerical simulation and the pilot results showed more than 20% OOIP over the water flooding. The actual production data was better than the numerical simulation, even in a reservoir with long-term 100% water cut. Daqing Oil Field obtained rather high oil recovery with the low acid number crude oil.

ORS-41 was used in Field No. 4. Laboratory tests showed that adsorption was minimal for this surfactant. The results of four of these tests are shown in Figure 1. Oil recoveries were exceptionally high using 0.3wt% ORS-41, 1.2% NaOH and 1000 mg/L polymer. The study concluded that over 20% OIIP over water flooding oil could be recovered using ASP, chemical cost per ton of incremental oil was calculated to be about US$5/bbl.

References: SPE 57288, 36748

Tanner Field ASP Project, Wyoming, USA

The Tanner field is a sandstone formation containing 21° API gravity crude with a viscosity of 11 cp at a reservoir temperature of 175º F (79º C). The reservoir is 8915 feet (2717 m) deep with an average porosity of 20% and an average permeability of 200 mD. The reservoir is 25 ft (7.32 m) thick. The Tanner field ASP flood is very unique in that alkaline-surfactant-polymer injection began after a short water flood when the oil cut was 43%.

The ASP flood used 1.0 wt% NaOH, 0.1 wt% ORS-41 and 800 mg/L Alcoflood 1275A (polyacrylamide polymer). 0.251 pore volume (PV) of ASP solution amounting to 642,000 bbls was injected followed by 0.52 PV or 644,685 bbls of tapered polymer were injected. This was followed by 0.092 PV or 236,000 bbls of water through 2005.

The chemical and plant costs were $1,430,000. Incremental operating cost was negligible since a water flood would have operated throughout the chemical injection. Figure 2 shows the results before and after the introduction of the ASP flood to the Tanner field. Note the sharp divergence in the actual oil cut after ASP and the extrapolated oil cut if ASP were not to have been employed.

The project is projected to produce an additional 17% of the OOIP beyond that producible by water injection. The total cost of chemicals, plant and engineering was US$ 5.85 per incremental barrel of oil recovered. Payout was 2.5 years based on the cost of oil in the period 2000 - 2005.

Reference: SPE 100004

Sho-Vel-Tum Field ASP Project, Oklahoma, USA

An ASP flood in the Sho-Vel-Tum field sponsored by the US Department of Energy. This was a small pilot test to prove the feasibility of the ASP process. The well is located in Oklahoma, USA and the reservoir is only 700 feet (214 m) deep making it the shallowest well in the United States where an ASP flood has been initiated. The well has been producing for over 40 years and was producing 4 bbl/day before the ASP project was initiated. The ASP project increased average oil recovery from 4 bbl/day to 20 bbl/day. The pilot project added 10,444 barrels of incremental oil over a period of 1.3 years.

The ASP system consisted of 0.5 wt% ORS-62 2.20 wt% Na2CO3 and 1000 mg/l Alcoflood 1275A polymer in softened water. Project costs were $26,479 for 14,000 lbs polymer, $25,479 for 47,980 lbs ORS-62 and $14,854 for 73.3 tons of sodium bicarbonate. The cost per incremental barrel oil is estimated to be about $4/bbl making the project economical even when the oil price was $18/bbl.

Reference: SPE 84904

Taber South ASP Project, Alberta, Canada

Taber South was producing 300 bbl/day before the ASP flood. ASP injection started in June 2006. Production increased to 1,502 bbl/day as of December 2007. Oil cuts increased from 1.7% to 7.3% over the same period.

Reference: Masters Energy February 2008 Corporate Presentation

 

Alkali Surfactant Flood Field Published Results

Big Sinking Field AS Flood, Kentucky, USA

Alkali surfactant was implemeted to improve the injectivity of a waterflood located in the Big Sinking Field, Kentucky USA. The reservoir contains 100 Million barrels of oil at a depth of 1150 feet (350 meters) and a bottom hole temperature of 30º C. The reservoir is 25 feet (7.32 meters) in thickness and the permeability is 45 mD. The field was experiencing high water cuts and very low injectivity. After injecting a solution containing 0.8 wt% sodium hydroxide (NaOH) and 0.1 wt% ORS-162HF the injectivity was improved 220%. This solution lowered the interfacial tension (IFT) between the injection brine and the crude oil in the reservoir from the original value of 23.6 dyne/cm to 0.001 dyne/cm.

Pilot tests were run in 2003 by first injecting fresh water to establish an initial injection rate. This was followed by injection of NaOH and ORS-162HF alkaline surfactant solution. The fresh water return after injecting 1,500 barrels (238 m3) increased from 41 to 75 barrels per day (6.5 to 11.9 m3). The injectivity was increased by 220%.

The economic analysis of the project showed that a 30 barrel (4.8 m3) increase in injectivity for a mature waterflood with an efficiency of 15:1 (barrels injected/barrel oil produced) would result in a payout of approximately 8 months with oil at US$25/bbl (US$4/m3). At today's oil prices of US $80-90/bbl this would result in a payout of less than 3 months.

 

Reference: SPE 89384

Angsi Field Offshore AS Flood, Malaysia

Alkaline surfactant pilot project was implemented in Angsi field located offshore Terengganu, Malaysia, to evaluate the effectiveness of the alkaline surfactant process in improving oil recovery through the reduction of residual oil saturation. Oil Chemical Technologies' SS 6-72LV was one the surfactant used in the pilot test. The alkali surfactant solution was injected into Angsi I-68 reservoir as a single well tracer test used to determine the residual oil saturation. The Angsi is the second largest reservoir with the expected recovery factor of 39% of the OOIP. The crude oil gravity is an average of 42 API. Oil viscosity is 0.3 cps at reservoir temperature of 119 °C.

Reference: SPE 109033