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.
A fully coupled dual-porosity model is developed and used to simulate a given field condition. History match from ten wells in Northwest China shows a significant and sustained production decline, despite a continuous increase in drawdown. A critical drawdown is identified, after which the drawdown increase effect is neutralized from that from the permeability reduction. A different drawdown increase strategy by maintaining a constant bottom hole pressure (BHP), yet increasing the far-field reservoir pressure is proposed and applied. This way the drawdown can be increased without reducing the near wellbore permeability. Production decline can be stopped and reversed. Simulations on the field indicate that more than 30% production rate increase can be expected from each well, depending on the in-situ stress level against the permeability changes in the formation. Identifying these critical drawdowns is also economically important, as ineffective drawdown increase can generate zero or negative incremental production, at extra cost.
Permeability reduction and production decline are well-known problems in stress-sensitive formations. Such a permeability change normally is evaluated in the lab when the confining effective stress changes is correlated to the permeability changes. Production declines are believed to be triggered by this permeability reduction when the near wellbore stresses are increased in these stress-sensitive formations. This phenomenon can be observed in the field but may not be specifically quantified, when an increasing drawdown is applied, attempting to increase production. Although simulations and history matches were performed extensively (Bai et al., 1994, Klkanl and Pedrose 1991, Chen and Teufel 1993, Chin et al., 1998) a comprehensive study on how to reverse a production decline in a stress-dependent permeability formation is desirable. In this study, a basic correlation between permeability and effective stress changes is utilized. The in-situ permeability and those corresponding stress levels are identified. We must emphasize that the formation permeability may change with the effective stresses, but the range of the stress changes and the corresponding permeability should be identified first so that we can anticipate if those induced stresses due to a drawdown change fall into the sensitive range. This is an important indicator if we may link the production declining issue to the stress sensitivity in these reservoirs. A procedure for simulating and solving a problem as such is proposed in this article. First of all we can determine what kind of stress-sensitive experimental tests should be performed and used for field production evaluation. Commonly, the permeability is defined as a function of the confining stress, which is in the principal stress direction. In what follows, we propose to define the permeability as a function of the normal stress to the principal flow direction, which is dictated by the natural fractures and the geological bedding. Furthermore, if plasticity and dilatancy occur, the shear component of the stress tensor should be also used. Secondly we can determine if a production decline can be reversed by controlling the wellbore drawdown, i.e. if the drawdown and stress concentrations fall into the sensitive range to the permeability indicated from the experiments. Thirdly we may diagnose if a production decline in a specific field is mainly caused by these stress sensitive permeability change. Finally we may find alternative ways to increase drawdown without bringing down the permeability particularly near a wellbore at the same time. In other words, once we can correlate producing well drawdown to the induced stress changes, which are in the stress-permeability sensitive range, then we can adjust the producing drawdown to serve the purpose for production enhancement. Once these factors are identified, a dual-porosity model is utilized for production calculations. It should be realized that without considering these factors, any attempt to increase production by lifting drawdown may be fruitless or neutralized by the consequence of permeability reduction. Production declines in a fractured carbonated reservoir northwestern China are observed and enhancing strategies are proposed.
Tight gas reservoirs are gaining attention as major unconventional reserve in the worldwide. In China, tight gas has increased to 50% of the proved natural gas reserves. To profitably develop such reserves, horizontal wells and multi-stage hydraulic fracturing techniques are applied to maximize the reservoir drainage areas and increase reservoir conductivity to the wellbores by creating flow channels in the tight reservoirs. Without in-depth study including reservoir characterization, full field modeling as well as well test and production data analysis, reservoir properties cannot be reproduced and well performance cannot be represented to accurately forecast production. Overestimating or underestimating of production rates creates tremendous loss for oil companies or operators.
This paper describes an integrated workflow for reservoir characterization and development of tight gas reservoir in the northwest China. The methodology starts with 3D geological modeling, hydraulic fracturing modeling result added to full field reservoir simulation, multi-scale reservoir coarse grid and millimeter hydraulic fracture refined grids to capture fractures’ effect on simulation result, well testing and history matching of post-fracturing production results checked for simulation accuracy, then do production forecast. This paper also includes the details of sensitivity analysis to enhance well deliverability, such as well placement, half fracture lengths, numbers of fracturing stages, etc. This work flow enables the feasibility of coupling dynamic data into static model, checking and updating reservoir data simultaneously. As a result, the simulation model can more closely reproduce reservoir properties and more accurately do production forecast. It is significant for understanding reservoir potential, reservoir evaluation, stimulation design, reservoir simulation, gas production forecast and enhancing recovery strategies for the full field development of tight gas reservoirs.
Sun, Hansen (China United Coalbed Methane Corporation) | Zuo, Jingluan (China United Coalbed Methane Corporation) | Liu, Xinghui (Pinnacle - A Halliburton Service) | Mayerhofer, Michael J (Pinnacle - A Halliburton Service) | Wu, Jianguang (China United Coalbed Methane Corporation) | Zhang, Ping (China United Coalbed Methane Corporation) | Wu, Xiang (China United Coalbed Methane Corporation)
The Qinshui basin covers an area of approximately 42,000 km2 with coal resources and is one of the important regions for coal production and coalbed methane (CBM) exploitation in China. There are two major coalbeds that are important for CBM development. These coalbeds are laminated among sand, shale, and limestone formations and are located approximately from 200 to 1100 m in depth across the basin, with an average thickness between 3 and 6 m. This paper presents a case history of fracture evaluation for a CBM development project in the basin. In this study, fracture growth behavior was evaluated using fracture modeling and microseismic monitoring techniques. The instantaneous shut-in pressure (ISIP) for some treatments in the area of this study was well above the formation overburden stress. Closure stress obtained from diagnostic injection tests was high but lower than the overburden stress. Microseismic mapping results indicated significant fracture complexities, ranging from both confined and excessive height growth to asymmetric fracture growth and multidirectional fracture growth. An abundance of microseisms were detected, but most of them were located in the brittle sand and shale formations below and above the target coalbed. The complex fracture growth is believed to be caused by complex stress regimes and geologic settings in the study area. Fracture closure stress analysis from offset wells confirmed that stress variation was the primary reason for asymmetric fracture growth. Fracture modeling revealed that viscous fluids provided better fracture conductivity in the target coalbed than KCl water, as most proppant would settle below the target coalbed because of the poor transport capacity of water when KCl water was used alone. Based on the results from this study, improvements in fracture treatment design and well spacing should be considered. This paper demonstrates the benefits of an integrated approach to understanding hydraulic fracture growth behavior, which is important for developing a new CBM reservoir.
It is well known that heterogeneity is one of the most important factors in affecting production performance. These include oil production rate, oil recovery before water breakthrough, water cut, etc. However, it has long time been a challenge to correlate the heterogeneity and the oil production performance quantitatively, especially in low permeability reservoirs. To this end, fractal dimension inferred from mercury-intrusion capillary pressure data and other parameters were used to quantitatively characterize the heterogeneity of rock in this study. Over 100 core plugs were sampled from different wells in a low permeability oil reservoir. Routine and special core analysis tests were conducted in these core samples with a permeability ranging from less than 0.1 to over 100 md. Correlation between heterogeneity and oil production performance was investigated at both the microscopic (core) and macroscopic (well and reservoir) scales. The results demonstrated that the fractal dimension was correlated with the production performance at microscopic and macroscopic levels. The oil production rate and the water breakthrough time show an inverse relationship with fractal dimension, while the water cut shows a direct relationship with fractal dimension.
Hou, Shengming (China U. of Petroleum East) | Ren, Shaoran (China U. of Petroleum Beijing) | Wang, Wei (China U. of Petroleum) | Niu, baolun (SINOPEC) | Yu, Hongmin (Xinjiang Oilfield Company) | Qian, Genbao (Xinjiang Petr. Admin. Bureau) | Gu, Hongjun (Xinjiang Oilfield Company) | Liu, Baozhen
XinJiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (<14×10-3µm2). These reservoirs are featured with light oil in moderate depth, high reservoir pressure, but relatively low reservoir temperature (65~78oC) and low oil viscosity (<10mPa•s). Primary production and limited water flooding experience have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Gas injection has been optioned as an alternative secondary or tertiary technique to maintain reservoir pressure and/or increase sweeping and displacement efficiency. In this study, the feasibility of air injection via a low temperature oxidation (LTO) process has been studied. Laboratory experiments were focused on LTO characteristics of oil samples at low temperature range and core flooding using air at various reservoir conditions. Reservoir simulation studies were conducted in order to predict the reservoir performance under the air injection scheme and to optimize the operational parameters. The oxygen consumption rates at reservoir temperature and IOR potentials at different reservoir conditions were assessed for a number of selected reservoirs in the region. A pilot project has been designed based on experimental data, reservoir simulation results and field experience of air injection gained in other regions of China. Issues related to safety and corrosion control during air injection and the project economics were also addressed in the paper.
Gang, Cao (Oil Prod. Research Institute) | Linghui, He (University of Science and Technology of China) | Zhaomei, Chen (Daqing Oilfield Co. Ltd.) | Xuecheng, Zheng (Daqing Oilfield Co. Ltd.) | Qingbo, Wang (Oil Prod. Research Institute) | Mingzhan, Chen (Daqing Oilfield Co. Ltd.)
Hailar Oilfield is a new block of Daqing Oilfield developed from the end of last century. In the beginning of the development, beam pumping unit was the only lifting method of the Oilfield. Due to the low pump efficiency and higher rod failure rate as well as the 2000m lift, beam pumping system was not as economic as other in blocks of Daqing Oilfield. As the result, PCP was put into production from 2005. Though all the four wells had a good performance with high pumping efficiency in the beginning, after several months' operation, rod strings suffered from severe oscillation and resulted in fatigue failures in a short period. Theoretical and experimental study indicated that, high working temperature (85 centigrade) and special oil characteristics caused much higher swelling degree of elastomer than in other blocks, which led to the increment of interference fit and friction force between rotor and stator.
In the initial application, although pump parameter and elastomer formula were adjusted before treatment to reduce the swelling effect, these adjustments didn't take into effect as predicted. In that case, a personalized PCP design was brought forward which gave an integrated methodology for PCP application in Hailar Oilfield. In this design, all the lifting parts from surface to downhole equipments were considered as a whole system. FEM analysis was applied to make a detailed description of the pump for different operating temperature. Based on deeper adjustment of elastomer and pump's structure parameters, the optimum design of rod and other equipments were take into consideration as well. In the end of 2006, 4 new personalized design pumps were put into production. In the following year, despite of small oscillation in the first few days due to the influence of treatment water, all PCP systems performed stably with high efficiency.
Hailar Oilfield located in the northeast of Inner Mongolia Autonomous Region, near the frontier of China and Mongolia. It was a continental facies deposit basin which was developed from 1980s. See Fig. 1. Till the mid of 2007, the oil production rate has reached 250,000 tons. In the beginning, the lifting methods of the oilfield were beam pumping system and bailing lift system. The production rate per well was around 10 m3/day, and many of them were under 5 m3/day. The lift of producers ranged from 1600m to 2500m, and temperature was from 70 to 90?. Due to the low displacement and higher lift on the average, beam pump system and bailing lift system wasn't so economic. In the beginning of 2005, one PCP well (Well#0) was put into production with 1400m lift. The system operated stably and was pulled out till the mid of 2006 due to the new development requirement of the block. According to the good performance of this case, PCP lifting technology was recommended to be applied in higher lift wells (above 1800m) in Hailar basin.
Pilot Test of PCP Lifting System
In 2006, a pilot test was implemented including 4 PCP wells in Hailar Oilfield from August to November. The pump efficiency was very high up to 90% in the beginning of the operation. But several weeks later, high flunctuate of operating loads were found in all the wells. See Fig. 2. Obvious oscillation could be observed from the surface polished rod and abnormal sound could be heard clearly, which indicated the pumps weren't operated in the constant speed. Under this abnormal operating condition, rod and pump failures were frequent in the following several months. Up to April, 2007, Well#1 has a rod failure after one month operation. Well#2 has three rod failures in five months. Well#3 has two rod failures in two months. Except that Well#3 operated normally, all the other three wells' average running life was around two months.
He, Liu (Daqing Oilfield Co. Ltd.) | Yong, Bi (Daqing Oilfield Co. Ltd.) | Guochen, Shi (Daqing Oilfield Co. Ltd.) | Zhongguo, Wang (Daqing Oilfield Co. Ltd.) | Chaoyong, Liu (Daqing Oilfield Co. Ltd.) | Zhaoping, Jiang (Daqing Oilfield Co. Ltd.)
Trouble-shooting technique is an important part in artificial lift technology. Based on wave equation created by Gibbs from 1970s, dynamometer card method has been applied successfully in beam pumping well's trouble-shooting technique. As for PCP wells, there's no such the same parameter as beam pumping unit's dynamometer card which could indicate systems performance directly. In Daqing Oilfield, PCP trouble-shooting technique has been studied for more than ten years. Many methods were tried, such as operating current, effective power, rod string's operating torque and axial load, oscillation frequency, etc. Application indicated that, among all the above parameters, rod string's operating torque and axial load were the most effective ones to reflect PCP system's operating status to date. However, it was still difficult to give a clear description of a PCP system without the assistance of other parameters.
This paper overviewed the development history of PCP well's trouble-shooting technique in Daqing Oilfield. A comprehensive testing and trouble-shooting system was presented consisting of a loads sensor, a wireless signal processing system and the trouble-shooting software. The diagnose model was created on the basis of PCP wells' operating loads and the related production data base, which could distinguish ten types of operating status of PCP system. In the past few years, this system has been applied in more than 300 PCP wells in Daqing Oilfield. Although the compatibility of the model for different driving methods needs to be improved for a wider application(such as ASP flooding), the system has been approved to be convenient and effective in water flooding and polymer flooding area which could apply a good reference for other issues.
PCP was used in Daqing Oilfield from 1980s. To date, there are more than 3000 PCP wells in operation. With the increment of PCP number, the requirement for PCP trouble-shooting technique has been more and more urgent in the past ten years. In the initial stage of 1990s, PCP's trouble-shooting and diagnosis were based on empirical evaluation of production data such as production rate, dynamic level and operating current, most of which were the same as beam pumping system. The problem was that none of these parameters could describe downhole system's performance directly and exactly.
Referring to Gibbs' wave equation theory and dynamometer card of beam pumping system, a new trouble-shooting method was created on the basis of PCP rod sting load measuring and analysis as well. And the polished rod load measuring device was the core of the technique. From the early of 1990s, several generations of devices were developed with higher accuracy and easier application. The diagnosis theory also developed from the simple experienced judgement to more scientific models.
Yang, Ye (Daqing Oilfield Ltd.Co.) | Han, Hongxue (U. of Waterloo) | Dusseault, Maurice B. (U. of Waterloo) | Xu, Baoci (U. of Waterloo) | Wang, Xianjun (Daqing Oilfield Co. Ltd.) | Yu, Ying (Production Engineering & Research Institute of Daqing Oilfield Co. Ltd. ,PetroChina)
We present successful hydraulic fracture treatment practices in water sensitive tuffaceous reservoirs in Hailar Basin, China. The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracture treatments. The article describes the geological engineering framework, mineralogy investigation, hydrolytic weakening experiments, as well as application and results of new kinds of fracturing fluids.
Rock mineralogy investigations indicated that rocks in the reservoir have a strong water sensitive property and a strong component of plastic behavior. Some tuffaceous rocks are rich in alkali minerals and become soft when exposed to aqueous fracture fluids. Although the fracture opening mechanism is the same as for normal sandstone, fracture extension is relatively suppressed and the fracture width is different from elastic predictions for normal sandstone.
The analysis led to the changes in treatment stratages. The key difference from previous treatment is that clay content and concentration of different minerals were taken into consideration of fracture fluid design. Different kinds of emulsified fracturing fluid were designed used to mitigate swelling and hydrolytic weakening effects. By the end of 2005, 163 intervals in 66 wells have been treated using these new kinds of fracturing fluids, with a success rate of 97%.
Massive hydraulic fracturing treatments in low-permeability sandstone reservoirs are common practices; wherease, stimulating tight, a volcanic-origin reservoir is far less common. Several reports of successful hydraulic fracturing treatments in volcanic reservoir rocks can be found; e.g., Weijers et al. (2002) reported fracturing practices in volcanic tight gas reservoirs in the Minami-Nagaoka gas field in Japan. Also, Antoci & Anaya (2001) discussed massive fracture treatments in tight gas zones in the Neuquen Basin (Argentina) where the lower parts of the oil zone are tuffaceous porphyrites.
In recent years, tight tuffaceous reservoirs were discovered through exploration activities by Daqing Oilfield Ltd. in the Hailaer Basin. The Hailaer basin, together with the East Gobi Basin, and Tamsag Basin, are of a series of basins that formed in the China-Mongolia border region during a period of Late Jurassic-Early Cretaceous (Tse 2003, Johnson & Graham 2004). They have samiliar geological sedimentary structure and lithology. The basins are dominantaly nonmarine synrift sediment and volcanic flows fillings. The reduced porosity and permeability may be a concern because of rift-related volcanism and zeolite cements associated with volcanic input into saline-alkaline lakes. This system was eventually overwhelmed by volcanic debris during eruptions (Johnson & Graham 2004). Core analysis of the tuffaceous rock in Hailaer basin gave a porosity range of 5.6 to 21.7% (average 15.1%) and a permeability range of 0.03×10-3 to 27.4×10-3 µm2 (average 1.17×10-3 µm2).
The reservoirs are of too low permeability to be placed onto production without massive hydraulic fracturing treatments. The preliminary two field experiments of fracturing in the tuffaceous rocks (carried out in 2002) were failed. Figure 1 illustrates a standard pressure-time treatment curve for one layer in one well. In this case, after fracture initiation, the stable fracture fluid injection pressure was ~26 MPa at the pump. Proppants experienced sudden tip screen-out when the concentration reached 200 kg/m3, preventing further fracture propagation into the reservoir.