This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Jiang, Tongwen (Tarim Oilfield Company, Petrochina) | Zhang, Hui (Tarim Oilfield Company, Petrochina) | Wang, Haiying (Tarim Oilfield Company, Petrochina) | Yin, Guoqing (Tarim Oilfield Company, Petrochina) | Yuan, Fang (Tarim Oilfield Company, Petrochina) | Wang, Zhimin (Tarim Oilfield Company, Petrochina)
The Kelasu gas field located in northern Tarim Basin had experienced four tectonic evolutions, with the most intense deformation between northern margin of the basin and southern Tianshan Mountains. A series of sandstone faulted anticline gas reservoirs were produced after the Himalayan movement. Faults were the main channel to transport natural gas from Jurassic coal-bearing formation to sandstone reservoir in Cretaceous. Simultaneously, the faults play a key role for fluid flow during the development of the gas field, but it is a huge challenge to evaluate the influence of faults on fluid flow quantitatively with depletion. To solve this problem, an integrated research combined geology, geomechanics and gas reservoir engineering was conducted. Firstly, 6 geological factors associated with connectivity and sealing properties of faults was analyzed to determine the critical factors among them. Secondly, based on 4D geomechanical modeling and 3D stress analysis of faults' plane, a calculation model of faults geomechanical activity index (FGAI) was built. Finally, the relationships between faults geomechanical activity and performance of gas field development were investigated to understand the influence of faults' mechanical behavior on production and water invasion during development in Kelasu gas field.
It is shown that faults geomechanical activity has profound influence on the performance of Kelasu gas field. 1.The faults geomechanical activity is one of key factors to control permeability, which can indicate the difference of permeability around faults and permeability variation during depletion. 2.With the depletion during exploitation the in-situ stress regime in Kelasu gas field changed from strike slip to normal faulting, and the heterogeneity was also gradually increasing which two resulted in the variety and complicate of faults' geomechanical activity. 3.It is found that there is a good correlation between the faults geomechanical activity and water invasion. The water breakthrough was early and gas-water interface rose fast near the faults with higher geomechanical activity index during depletion. 4.The complex relationship between stress field and faults system resulted in a great difference of faults geomechanical activity index in different location of reservoir. FGAI (Faults geomechanical activity index) is the highest in western reservoir, followed in turn by the eastern, northern, southern, so there is the most rapid uplift of gas-water interface in the western, followed in turn by other parts. Based on evaluation of faults geomechanical activity in this area, this reservoir could be divided into three blocks by different water invasion risk. Areas and gas wells with high risk water invasion were warned in advance. 6.For optimization of well placement, we found that FGAI is relatively low in northwestern reservoir, the fault sealing ability is high, the research provided one of basis for the placement of a new gas well.
A fault geomechanical activity index (FGAI) model for the gas reservoir with complex structure and high pore pressure and high in-situ stress was established. And its validity and effectiveness toward development of gas field was proved by production data and information. Based on the quantitative classification and description of faults geomechanical activity to investigate the influence of faults on water invasion, the mechanism of heterogeneous water production was determined in Kelasu gas field. The research provided the sealing evaluation of faults for new wells placement and risk prediction of water breakthrough for gas wells during depletion.
Zhang, Fuxiang (Tarim Oilfield Company) | Zhang, Hui (Tarim Oilfield Company) | Yuan, Fang (Tarim Oilfield Company) | Wang, Zhimin (Tarim Oilfield Company) | Chen, Sheng (Tarim Oilfield Company) | Li, Chao (Tarim Oilfield Company) | Han, Xingjie (Tarim Oilfield Company)
Keshen gas field, located in Kuqa Depression of Tarim Basin, northwest China, is an ultra-deep (7000m), high pressure and high temperature fractured tight sandstone gas reservoir with low permeability of 0.09mD and strong stress anisotropy about 30 MPa in horizontal stress contrast. For economic development, hydraulic fracturing is necessary in this reservoir.
To understand the mechanism of hydraulic fracturing and evaluate the fracability and fracture this reservoir efficiently, an integrated research has been conducted. We established a geomechanical model which described vertical and horizontal distribution of the geomechanical parameters in this reservoir. A fracturing experimental simulation was conducted with large size rock samples to analyze the interactive relationship between natural fractures and hydraulic fractures during fracturing. We also carried out a sensitive study to comfirm the key parameters for optimizing fracturing treatment design. Finally a new fracablity index calculation method suitable for fractured tight sandstone was built.
It is shown that for fractured tight sandstone reservoir with strong stress anisotropy like Keshen, shear deformation of natural fractures is a key factor of creating fracture area with high permeability. And the evolution of fracture area during fracturing experienced three processes. (1)Fracturing fluid extends along natural fracture at the initial fracturing stage; (2)At a certain injection pressure, slight shear deformation happens along the plane of natural fracture. As injection pressure increases, fracturing fluid breaks through a weak point of natural fracture and propagates along the direction of maximum horizontal stress; (3)A new set of fractures with combination of tensile-opening and shearing are formed, which are caused by changing of in-situ stress field around natural fractures. These three processes happen alternately and eventually form an ideal fracture area. It is also found that post-fracturing productivity has a close correlation with the shear deformation of natural fractures. At the axis of structure or fault developed area, natural fractures with strong potential shear deformation trend are more easily stimulated, and productivity can be high after fracturing. By contrast, fractures at structure saddle or steep part have weak potential shear deformation trend and are difficult to be stimulated, and thus productivity would likely be lower. Accoding to the mechanism of fracturing, we considered that the fracability of fractured tight sandstone is a function, and the parameters are in situ stress, shearing slip deformation, brittleness and fracture toughness.
Mechanisms of hydraulic fracturing and key factors effecting well productivity after fracturing in Keshen reservoir have been found through this study. Hydraulic fracturing treatment design and execution were conducted based on this study. After fracturing, the production performance (open flow potential) of stimulated wells increased by four-fold on average.
Yang, Haijun (Tarim Oilfield, Petrochina) | Zhang, Hui (Tarim Oilfield, Petrochina) | Cai, Zhenzhong (Tarim Oilfield, Petrochina) | Chen, Sheng (Tarim Oilfield, Petrochina) | Yuan, Fang (Tarim Oilfield, Petrochina) | Wang, Haiying (Tarim Oilfield, Petrochina) | Wang, Zhimin (Tarim Oilfield, Petrochina) | Li, Chao (Tarim Oilfield, Petrochina)
Reservoir performance in tight sandstone is influenced by geomechanical behavior of natural fractures profoundly. Keshen gas field, located in Kuqa Depression of Tarim Basin, northwest China, and the pay zone is naturally fractured sandstone undergone strong tectonic activities of squeezing and thrusting. To understand key factors to productivity in this reservoir, an analysis of geomechanical response of natural fractures was presented that elaborated the relationship between productivity and geomechanical characteristics of fractured tight gas reservoir.
To evaluate the geomechanical response of natural fractures quantitatively, a comprehensive laboratory testing program (covering more than 130 core samples from 7 wells) was performed, 1D geomechanical model was built for 23wells which described distribution of the mechanical properties and in situ stress in Keshen reservoir. The normal stress and shear stress of each fracture plane were calculated to compare the relative mechanical response of natural fractures across the anticline structure. We then simulated mechanical response of natural fractures under different pore pressure according to Mohr-Coulomb failure criterion, and obtained the correlation between geomechanical response and open-flow potential of wells.
The results illustrated that well productivity in Keshen reservoir was closely related to the geomechanical response of natural fractures. At the crest of structure and faulting area, the favorable combination of in situ stress and natural fracture strike resulted in high shear-to-normal stress ratio and high fracture conductivity. On the other hand, at the saddle and flanks of this structure, the ratios were lower and so did for well conductivity. The difference of well productivity for the two cases could be up to forty times. And simulation under different pore pressure showed that the proportion of natural fractures reaching critical stress state in the wellbore affected the flow potential directly. In other words, some wells developed natural fractures with strong shear deformation potential corresponding to a high productivity. And then with the depletion, the dynamic change of mechanical response of natural fractures was also closely related to productivity. Taking 3 new wells for example, as pore pressure of reservoir decreased by 10MPa, productivity of 2 wells dropped since the shear-to-normal stress ratio of 70% natural fractures reduced, their productivity was lower than adjacent wells even after fracturing. The productivity of the third well maintained high because the shear-to-normal stress ratio of all natural fractures increased.
It was revealed that the geomechanical response of natural fractures was a controlling factor of well productivity in Keshen tight sandstone gas reservoir. The information obtained from this study provided critical input for reservoir stimulation and development for the gas field.
Cai, Zhenzhong (Tarim Oilfield PetroChina) | Zhang, Hui (Tarim Oilfield PetroChina) | Yang, Haijun (Tarim Oilfield PetroChina) | Yin, Guoqing (Tarim Oilfield PetroChina) | Zhu, Yongfeng (Tarim Oilfield PetroChina) | Chen, Peisi (Tarim Oilfield PetroChina) | Han, Xingjie (Tarim Oilfield PetroChina)
YM2 Oilfield is an ultra-deep carbonate oilfield located in the northern uplift of Tarim Basin in western China. We have identified 108 seismically resolvable faults formed over three periods. These faults control the distribution of oil and gas accumulation units. Permeability differs significantly amongst various faults, and various sections of the fault planes. There has been no effective quantitative evaluation measure on the relative opening or sealing of faults for a long time, the sealing capacity of the faults have not been evaluated so far. This has a negative impact on the evaluation of accurate reservoir compartmentalization and partitioning, and evaluation of various oil and gas flow units which are critical for constraining the development program and production performance of oil field.
There are many geological factors that influence the permeability of faults, such as burial depth, fault throw, dip angle, strike, lithology variation, pore pressure and the in-situ stress field. After evaluating these factors in the YM2 oilfield, we determined that the critical factor that controls fault permeability is the geomechanical response of faults under the current stress field. In order to determine if the faults are permeable relatively in the current stress state, we established the geomechanical model of YM2 reservoir which describes the present-day stress regime, along with the vertical and horizontal distribution of the geomechanical parameters of this reservoir. Based on the interpretation of 3D seismic data, we characterized the spatial combination relations of faults in the reservoir and extracted the occurrence information of each fault according to certain step size. Then, we calculated the normal and shear stress acting on the various fault planes in order to evaluate whether those faults are permeable relatively in the current stress state.
It is shown that the fault zone not only controls the evolution of local structure, but also significantly impacts the regional stress field, which in turn impacts the geomechanical response of fault zone and their permeability. The NW strike-slip faults in the southeastern part of the oilfield in particular are characterized by high values of normal stress and low shear-to-normal stress ratios with relative lower permeability. Producing wells in this region have low productivity and weak connectivity amongst wells. In contrast, the northwestern area that has NE strike-slip faults and NS thrust faults have low stress but high shear to normal stress ratios, and hence relatively higher permeability. The surrounding wells have higher inter-well connectivity and are more productive. In the same fault zone, as the relationship between stress and fault orientation changes, the potential mechanical behavior also affects permeability variation and well productivity. The main reason is that the interaction between faults and stress field leads to the increased reservoir heterogeneity in the fault zone or among faults. Based on this concept, we chose several advantageous well locations, where horizontal minimum principal stress is low, anisotropy of horizontal stress and shear-to-normal stress ratio are high.
This study classified the faults of YM2 oilfield based on geomechanical response, clarified permeability variation of various fault zones and their impact on productivity, and then it provided the quantitative selection basis for well placement and wellbore trajectory optimization.
Pressurized MudCap Drilling (PMCD), a variant of Managed Pressure Drilling (MPD), is known for allowing drilling to continue despite a total loss of circulation, while at the same time monitoring and controlling the entry of influx into the wellbore. A weakness of this technique is that the well still has to be killed prior to pulling out of the hole, which can be time-consuming and ultimately lead to reservoir damage. Utilizing a downhole isolation system to eliminate the need to kill the well during and after PMCD operations would therefore greatly improve the efficiency and effectiveness of this drilling technique and enhance its acceptability in operations where well productivity is a major consideration.
A combination of MPD and downhole isolation technologies was recently used successfully to drill a highly prolific, fractured gas reservoir in Suban Field, South Sumatra, Indonesia, resulting in wells capable of producing in excess of 300 mmscfd. MPD with downhole isolation allowed drilling to continue even with total loss of circulation, increased the safety margin of operations, reduced the amount of mud and lost circulation materials (LCM) required, minimized formation damage and made the running and installation of the completion assembly possible without the need to kill the well. The project demonstrated the clear and practical advantage that can be gained from combining these two technologies.
This paper focuses on how MPD and downhole isolation technologies were successfully integrated to produce high-rate gas wells in the Suban field and details how the system was effectively utilized for the first time to produce improvements in the safety and efficiency of drilling and completion operations, as compared to previous methods used in the area. It will also present the equipment, set-up, processes and procedures used in integrating these two technologies.
Suban Field Development
The Suban field is located in the ConocoPhillips Indonesia Corridor Block PSC of South Sumatra and has gas-in-place estimates in excess of 7 TCF. Suban Field was discovered in 1998 and with production starting in December 2002 from fractured basement rocks as well as overlying clastic and carbonate units. Table 1 shows the basic reservoir properties of this field, while Figure 1 provides its location.
ConocoPhillips currently operates the development of the field. Partners include Talisman and Pertamina. In 2004 ConocoPhillips recognized the opportunities of utilizing big bore wells for its Suban field development.
Early field production was dominated by two wells with extensive reservoir fracturing. Production potential from the reservoir was considered excellent and using well test data, it was determined that the fracturing system was well connected and that large areas of the reservoir could be drained from central locations.
While production rates were relatively high, it was clear that performance from these early completions was less than optimum and that the 5 ½?? production tubing strings were under-sized relative to reservoir flow potential. Poor well flow efficiency was evidenced by large apparent non-Darcy skin effects seen from multi-point flow tests and pressure buildup tests. Non-Darcy skin is a term used to characterize a pressure drop near the wellbore that is caused by turbulent flow that increases as a function of the flow rate. In simple terms, it was apparent that well flow potentials could be much higher, if the non-Darcy effects could be eliminated or reduced.
Oil Production from Basement Reservoirs OIL PRODUCTION FROM BASEMENT RESERVOIRS - EXAMPLES FROM INDONESIA, USA AND VENEZUELA Tako Koning, Texaco Angola Inc., Luanda, Angola Abstract. Oil is produced from basement rocks in a number of countries including China, Vietnam, former USSR (West Siberia), Ukraine, Indonesia, Libya, Algeria, Morocco, Egypt, USA, Brazil and Venezuela. Oil fields producing from basement in Indonesia, United States, and Venezuela are described herein and serve as models for basement oil fields exploration and production. contacts, and a possible unrecognized water-
bearing fracture system. The Tanjung field in the Barito Basin, Although oil production from basement South Kalimantan, was discovered in 1938 and rocks is not a common occurrence worldwide, has produced over 21 million barrels of oil there is significant oil production from such from pre-Tertiary basement rocks. Oil occurs reservoirs in a number of countries. Two in volcanics, pyroclastics, and metamorphosed fields in Indonesia, Beruk Northeast and sandstones and claystones, which are locally Tanjung, serve as examples that commercial deeply weathered and fractured. The Beruk volumes of oil can be produced from basement Northeast and Tanjung fields share many in Indonesia. Indeed, recent successful similarities. For example, both fields occur exploration for gas in South Sumatra has within faulted anticlines. The overlying reinforced the concept that basement is a valid thickness of Tertiary sediments in both fields exploration target in Western Indonesia and is less than 2000 meters. The likely oil source that whenever possible, wells drilled through rocks for these fields are the adjacent and the Tertiary objectives should be deepened into deeper Tertiary shales. The Beruk Northeast basement to evaluate possible oil or gas and Tanjung fields indicate that pre-Tertiary accumulations. In Kansas, oil is produced basement is a valid oil exploration objective in from fractured quartzites whereas in the Tertiary basins in Western Indonesia and California, oil is produced from fractured that, whenever feasible, exploration wells in schists. In Venezuela, prolific oil wells these basins should be drilled into basement. produce from fractured granite in the La Paz Indeed, exploration targeted for basement and Mara oil fields. hydrocarbons has met with recent success in South Sumatra, where operator Gulf Indonesia INDONESIA has reported the significant Suban gas discovery. Three wells drilled in 1999 in the Oil production from pre-Tertiary basement Suban field have defined a gas pool located rocks is rare within the Tertiary back arc within fractured pre-Tertiary granites. Gas (foreland) basins of Western Indonesia. The flow rates of 26 MMCFGPD were obtained Beruk Northeast field is the only field in the from the Durian Mabok-2 well. Test data prolific Central Sumatra Basin that produces combined with seismic mapping indicates a from basement (Koning & Darm