Search

Reservoirs in the Tarim Basin located in Western China can exceed 6100m [20,000 feet] TVD and often classified as high- pressure high-temperature (HPHT). These sandstone formations are ultra-deep with presence of natural fractures and temperatures approaching 190°C [375°F] and reservoir pressure ranging between 110 to 125 MPa [16,000 to 18,000 psi]. The development of such resources comes with unique challenges that require a coordinated and integrated approach when drilling, collecting sub-surface data, well completions, and intervention operations. All of these tasks pose unique challenges that are often not encountered in other hydrocarbon basins. Hydraulic fracturing is a critical component to the well completion practice and is obligatory in order to maximize well productivity. This type of reservoir poses serious technical challenges that must overcome and account for the geological, geomechanical, and petrophysical interpretation. The integrated approach towards understanding the reservoir combined with the use of a novel fracture diversion technology was undertaken to ensure the maximum surface area contacted by the fracture with the reservoir and wellbore. The hydraulic fracturing design process involved the identification of intervals for multiple perforation clusters across the 200m [650 feet] reservoir section and then executing multiple stage stimulation treatments in which a fluid and proppant schedule would be pumped followed by the application of this dynamic diversion technology. This paper will discuss this case history from a workflow perspective, introduction of this fracturing technology while using a weighted fracturing fluid with a specific gravity of 1.3, the treatment observations identified through real-time microseismic, and discuss how the better reservoir understanding enabled an improved completion strategy. The ten wells with this approach are best in class from a production standpoint when compared to the three tier reservoir potential ranking approach. Finally, the lessons learned from the first phase of this project will help guided future development activities.

Abstract There is abundant natural gas in Kuqa foreland area of Tarim basin, it has characteristics of reservoir burial depth (5500–7500m), high gas reservoir pressure (105–125Mpa), complex corrosive medium (the partial pressure of CO2 is beyond 2 Mpa, the chlorinity is between 100000 ppm and 140000ppm), and the overburden lithology of gas reservoir is complex (there is heavy calcium rock and mudstone layer), which bring well integrality high challenge. During over three years practice, through exploring the extreme high pressure down hole string shock checker, tubing tongs torque field proving, establishing extreme high pressure complex corrosion behavior pipe simulation behavior laboratory evaluation criterion, supporting air spider and threaded He gas tight detection device, several techniques are formed initially including extreme high pressure gas well pipe simulation behavior evaluation technique, extreme high pressure gas well wellbore evaluation technique, extreme high pressure gas well string layout and mechanical check technique, completion string quality control technique, it provides dynamic guarantee for long-term secure manufacture in Kuqa extreme high pressure extreme deep gas reservoir. Introduction There are tremendous natural gas resources in Quka foreland area of Tarim Basin. But the deep buried depth (5500–7500m TVD), high gas reservoir pressure (105–125Mpa), complex corrosive medium (CO2 partial pressure: 1–4Mpa, chloride ion concentration: 100000–140000ppm) and complex overlying rock lithology all have brought big challenges for well integrity management after being brought into production. According to the international generally accepted definition (as shown in figure 1), gas reservoirs in Quka foreland area of Tarim Basin are typically "Extreme Deep, Extreme High Pressure and High Temperature" with very complex operating conditions. Considering that the low reservoir porosity generally less than10%,low permeability less than 1md and along with some natural fractures developed, most wells have to get better performance after acidizing or hydraulic fracturing. At the initial stage of development, super 13Cr gas seal tubing were used as working string in completion operation. Considering the cost and well control factor, we did the hydraulic fracturing through the same completion string and then put into production directly. Wellbores have already suffered from abnormal high pressure during drilling. Given 115Mpa reservoir pressure, weighed fracturing fluid were used during treatment in most wells and we had 100–120Mpa pumping pressure with 136Mpa as the highest wellhead pressure and 210Mpa bottom of hole treating pressure. Meanwhile, acidizing inhibitor only could limitedly protect super 13Cr tubing under over 150 ?, even tubing/casing corrosion or piercement has happened just during treatment and flowback. Initial statistical result of shows that 35.48% of wells have well integrity problems, 63% of which are tubing string failures, 16% are casing string failures, 21% are wellhead failures and other failures. Workovers have been operated in 5 shut off wells to reproduce, each of which cost 20–40 million RMB. After Analysis above, Tarim Oilfield focus on the tubing string failure as the key well integrity research direction, which cover 63% of all well integrity failures. By fully considering casing program before completion, pressure control during operation, field quality control during tubing trips and practices in some other key parts, the better effectiveness is gained.

TZ-I carbonate reservoir in the Tarim Basin, Western China is deep buried (>5000m), high temperature (>130°C), low-permeability, and severely inhomogeneous, and the natural fractures, vug and huge cavity often densely distributed in it. Because the aquifer energy is poor, horizontal wells can be adopted as recovery method to expose the area of reservoir as much as possible and connect more naturally fractured formation. But the open-hole interval is too long to be effectively stimulated by un-isolated general stimulation, so the multistage isolation fracturing technique should be conducted to exert the advantage of horizontal well and maximize single-well productivity. A novel one-trip open-hole completion and stimulation system was implemented successfully to isolate the long horizontal interval with multistage packers and sliding sleeve. During the process of treatment, the characterization of opening sliding sleeve is clear, moreover, the ISIP and pressure decline after shut-in is different between every stimulation interval, which shows the system is able to effectively isolate and stimulate specified intervals. The wells productivity increased dramatically after the multistage isolation stimulation, and much higher than the vertical well or general acid fractured horizontal well in the same trap. This shows the horizontal isolating stimulation technique can enhance production and reduce rig time significantly.

Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation. But because of serious acid leak-off and rapid acid/rock reaction speed, the length of effective acid etched fracture is always restricted, even the high viscosity acid and emulsified acid were applied; besides the effective duration of etched fracture was short, especially in deep well, because of the high closure stress acted on the fracture wall where the rock were softened significantly after contact with acid. In contrast, propped fracturing can create longer conductive fracture, and its effective duration is longer because the existence of proppant. The carbonate reservoir are deeply buried (>4500m) with high temperature (>130°C), ultra-low porosity/permeability, high young's modulus and tensile strength, and the natural fractures often densely distributed in it, all of which makes the propped fracturing difficult. A new temperature-stability and shearing resistance delayed cross-linked guar fracturing fluid with low damage was developed to qualify for the fracturing treatment. Small size high strength ceramic proppant was selected to fulfill the narrow width of fracture, and proppant slugs was utilized to erode the tortuousness of near-wellbore fracture path and plug near-wellbore multiple hydraulic and natural fractures. The technology countermeasure ensured the success of propped fracturing treatment. The net pressure and production history matching both indicated that the propped fracturing created longer conductive fracture and realized deep penetration. The well production increased dramatically after the stimulation. Besides, the comparison of production after gelled acid fracturing, surface cross-linked acid fracturing and propped fracturing in the same layer same well suggested that propped fracturing was more effective than the acid fracturing. The production test further showed propped fracturing could provide longer effective duration, and the well rate-maintenance capability was very excellent.

To compare the effect of different stimulation techniques on carbonate reservoir and optimize the techniques, Well T was selected as a case study to test with Mini acid fracturing, cross-linked acid fracturing and hyrraulic fracturing in the same pay zone. The study showed that the effect of cross- linked acid fracturing was better than mini gel acid fracturing, and hydraulic fracturing technique was the best comparing with the others. The new idea and methods for the carbonate reservoir stimulation was gotten from the success of the 3 tests on the well. Well T is a key wildcat well on some reef foreshore body. The well was an openhole well which was drilled on August 11th, 2004 till the depth of 4925m in Ordovician. The target zone was 4913.52-4935.00m, and the reservoir temperature was 120 °C. show was good in the target zone when drilling, and the well flowed 28936m3/d gas and a little crude oil with 8.825MPa of tubing pressure using 6mm choke without any stimulation. Mini -acid fracturing was conducted in this well and 102m3 of gel acid was pumped on September 23, 2004. The production of gas and oil were 44270m3/d and 8.26m3/d respectively using 5mm choke at 14.463MPa of tubing pressure after the mini-acid fracturing. Surface cross-linked acid fracturing technique was conducted on the same target zone on October 17th, 2004. 538m3 of fluid was pumped into the formation including 230m3 of pad fluid, 230m3of cross-linked acid, 56m3 of gel acid and 22m3of flush fluid. The rate was 3.5-5.6m3/min and wellhead pressure was 58-82MPa.The well produced 19906-51485m3 gas and 19.3m3 oil per day with the tubing pressure 14.99-10.03MPa using 5mm choke after the cross-linked acid fracturing. Hydraulic fracturing was done in the same well on November 9, 2004. A total of 473.1m3 of fluid including 47m3 of proppant was pumped into the wellbore (12.2m3 40-60 mesh and 23.3m3 20-40 meshes). The well produced 33907m3 gas and 28.69m3 oil (crude oil density 0.8575 at 20 °C, no water) per day with the tubing pressure 9.48-10.3MPa using 6mm choke after the treatment. The result was encoursging.

This paper presents a novel alcoholic acid system to remove the damage caused by frac fluid in tight gas reservoir. Damage resulting from hydraulic fractures takes two distinct forms: damage inside the fracture itself because of inadequate breaking of the fracturing fluid polymer; and fracture-face damage because of excessive leak-off. The objectives of laboratory experiments are to identify potential damage and aid selection of the optimum treatment fluid and design. A novel alcoholic acid flow tests illustrated the permeability increased because of pore & throat enlarged by using mercury intrusion experiments. It was critical in addressing issues of selection of fracturing fluids, polymer concentrations and breakers. Improved breaker systems show even greater benefit when used in conjunction with the lower loading polymer systems. The newer fluid systems enhance load recovery and reduce formation exposure to potentially damaging polymer residue. DB gas reservoir is a low porosity, low permeability reservoir in the northwest of China. Large scale of hydraulic Fracturing has been carried out as effective method to get high gas production rates. However, the gas production rate after treatment increased to 335,683m3/d, and then declined to 34,875m3/d rapidly. The skin factor from well testing after hydraulic fracturing was 112, which indicated fractures and formation may appear damaged seriously because of more than 60% of the load fluid can be invaded and trapped in the formation by entering the smaller capillary pores during higher injection pressures. The gas production rate recovered from 32,383m3/d to 301,374m3/d and kept constantly by using treatment method of a novel alcoholic acid system.