Production of ultra-heavy oils is economically and technically challenging due to the very high viscosity of heavy oils, sharp viscosity increase over a small temperature drop and high operating costs. Reservoir oil can't even be mobilized by steam stimulation only due to inadequate reservoir energy. Even after the oils flow to the wellbore, the viscosity of the oils may exponentially increase when transported towards the wellhead due to the geothermal temperature decrease. The liquid oil could naturally turn into solid bitumen at any point where the temperature drops. The longer the travelling distance to surface for the oil, the bigger temperature drop, the greater the oil viscosity, and the more severe production challenges.
This paper presents the challenges associated with the production of ultra heavy oil in deep reservoirs in China. Operational difficulties widely exist in mobilization of in-situ oil, flow of oil from formation to wellbore, lifting of produced fluids from wellbore to surface, and surface processing and transportation of hydrocarbons. The sandstone reservoirs, sitting at a depth from 1600 to 1800 meters and having no support of any aquifer, contain approximate 4 million metric tons of 1.02~1.05g/cm3 heavy oil reserve. The oil-bearing formations have an average porosity of 27~29%, an average permeability of 1 Darcy and an original reservoir pressure of 16~17.5MPa. The oil viscosity at reservoir conditions (80°C) ranges from 6000 to 10000 centipoises (cP). Always keeping oil at a relatively low viscosity for feasible pumping is the theme topic with the thermal oil production in this type of reservoirs.
To find fit-for-purpose solutions, challenges had been analyzed in details for each part of the entire oil producing process covering the oil flow from the reservoirs to surface. The oil viscosity change with temperatures, the impact of oil viscosity reducers on the mobility of oil compounded with steam stimulation and CO2 injection for providing the initial energy to mobilize the heated oil, optimization of horizontal wells, screening of suitable wellbore lifting technology including wellbore heating and insulation and suitable chemicals for reducing the oil-water interfacial tension, and the steam stimulation optimization had been studied carefully prior to well drilling.
So far, 26 horizontal wells were drilled with an average of 130 meters horizontal section. Production data showed daily liquid rates at 800 tons at 55% water cut for all 26 producers after one year. The average peak oil production, the average cycle oil production capacity, the average cycle cumulative oil production of a single well was 25 metric tons per day, 14 metric tons per day and 2130 metric tons respectively. The average oil-steam ratio was 1.46 with a maximum oil-steam ratio of 5.26. The technologies discussed in this paper had been proved effective to produce ultra heavy oil from 1600 to 1800 meters formations with oil viscosity at 50°C conditions ranging from 180,000 to 260,000 cP.
This paper presents a case study on the successful application of Non-Aqueous Fluids (NAF) in the Tian Mountain Front Block in North Border of Tarim Basin. Traditionally the wells in this area are drilled with water based mud. Due to the unpredictable divalent complex salt formations, the high temperature (up to 180 °C) and high pressure (mud weight up to 2.6 s.g.) conditions, significant non-productive time (NPT) and low rate of penetration (ROP) were encountered in dealing with wellbore instability, kicks, stuck pipe and downhole losses in the salt formations and fractured pay zone. The water base fluids would become unstable when they are heavily contaminated by divalent salts and/or brine influx.
Tarim Basin is the biggest oil and gas bearing basin in China. Total area is approximately 560,000 km2, including “dead sea” desert of around 337,000 km2. One of the most challenging field in terms of drilling difficulties lies in the north border of Tarim Basin: the Tian Mountain Fronts. The reservoir depths are over 7000 meters TVD and bottom hole temperatures are up to 180 °C. Analysis of a large quantity of offset well data1,2, operator internal reports3,4,5 and presentations6 was comprehensively carried out and it was observed that frequent downhole complications were encountered in three major formation sequences / intervals:
(1) Shallow formations above the salt formations:
Heavy losses and extremely low ROP are common in drilling the hard conglomerates above the salt formations. In the event that the salts are inadvertently penetrated, the high pressure brine influx would require higher mud weight to kill the well. This is normally followed by downhole losses and stuck pipe events.
(2) Inside the salt formation sequences:
When the water base mud is used, downhole losses and stuck pipe events would normally follow a high pressure brine influx. Stuck pipe is also often encountered when the highly mobile divalent salt formation is penetrated, depending on the mud weight and time exposed. It is believed that the salts are dominantly divalent and their creep rate is much higher than the monovalent salts (believe to be 20 times faster). The risk of stuck pipe is significant higher when divalent mobile salts are drilled.
Another hazard causing the heavy downhole losses and pipe stuck in drilling the salts formation is when the pay zone is inadvertently penetrated, since the mud weight required in drilling the salts is much higher than the mud weight required in drilling the pay zone. It has been a long standing problem to confirm the bottom of the salt sequences. It is common that the number of salts sequences is unpredictable and hence require technology for confirming the end of salt sequences is highly challengeable. Often salts are encountered again in the next interval after the casing has been set to isolate all salt sequences, because the determination of the end of the salt sequences has been made mistakenly.