The last decade has spotted a tremendous upsurge in casing failures. The aftermaths of casing failure can include the possibility of blowouts, environmental pollution, injuries/fatalities, and loss of the entire well to name a few. The motivation behind this work is to present findings from a predictive analytics investigation of casing failure data using supervised and unsupervised data mining algorithms. Scientists and researchers have speculated the underlying causes but to date this type of work remains unpublished and unavailable in the public domain literature.
This study assembled comprehensive data from eighty land-based wells during drilling, fracturing, workover jobs, and production. Twenty wells suffered from casing failure while the remaining sixty offset wells were compiled from well reports, fracturing treatment data, drilling records, and recovered casing data. The failures were unsystemic but included fatigue failure, bending stresses from excessive dogleg, buckling, high hoop stress on connections, and split coupling. The failures were detected at various depths, both in cemented and uncemented hole sections. Failures were spotted at the upper and lower production casing.
Using a predictive analytics software from SAS, twenty-four to twenty-six variables were evaluated through the application of various data mining techniques on the failed casing data sets. The missing data was accounted for using multivariate normal imputation. The study outcome addressed common casing sizes and couplings involved with each failure, failure location, hydraulic fracturing stages, cement impairment, dogleg severity, thermal and tensile loads, production-induced shearing, and DLS. The predictive algorithms used in this study included Logistic Regression, Hierarchal Clustering, and Decision Trees. While the descriptive analytics manifested in visual representations included Scatterplot Matrix, and PivotTables. Failure causes were identified. A total of five statistical techniques using the aforementioned algorithms were developed to evaluate the concurrent effect of the interplay of these variables. Nineteen variables were believed to possess the highest contribution to failure. Scatterplot matrix suggested a complex correlation between the total base water used in fracturing simulation and casing thickness. Logistic Regression suggested nine variables were significant including: TVD, operator, frac start month, MD of most severe DL, heel TVD, hole size, BHT, total proppant mass, cumulative DLS in lateral and build sections variables as significant failure contributors. PivotTables showed that the rate of casing failure was highest during the winter season.
This investigation is aimed to develop a thorough understanding of casing failures and the myriad of contributing factors to develop comprehensive predictive models for future failure prediction via the application of data mining algorithms. These models intend to provide a theoretical and statistical basis for cost-effective, safe, and better drilling practices.
There are several self-healing mechanisms, both natural and artificial, applied to cementitious materials. In recent years, microbially induced calcite precipitation (MICP) technology has garnered special attention in the fields of Microbiology and Civil Engineering. The technology involves the synthesis of calcium carbonate crystals at ambient temperatures in calcium rich systems. Biocementation occurs as active microbes diffuse through the cracks and micro-pits generating calcitic deposits owing to their metabolic pathway. The calcifying bacterial cultures produce urease or carbonic anhydrase enzyme which is capable of precipitating calcium in the surrounding micro environment as CaCO3. The bacterial degradation of urea locally increases the pH and stimulates the microbial deposition of carbonate. The calcium carbonate produced binds the soil particles together, thus cementing and clogging the grains, and hence improves the strength and reduces the hydraulic conductivity of the unconsolidated sands. Moreover, these precipitated crystals can thus fill the cracks and enhance the durability of cement, mortar, and concrete. Incorporating calcifying bacteria is the essence of developing a self-healing material or "bio-cementing" technology as bacteria behaves as a long-lasting healing agent.
The calcifying microbes can be isolated from different sources like water springs, soil, ocean, environments with high pH values or the cement itself. The purified strains can be grown for a 24-hour period in the laboratory and then blended with the cement or other materials depending on the desired application. A cheap carbon source like glycerol/molasses is supplemented to the mixture triggering fast bacterial multiplication. It was found that after the curing time of 28 days, tensile strength, micro-crack healing capacity, and durability increased significantly. The process is as simple as mixing bacteria into a cement paste. The technique for creating a high strength cement in a permeable starting material involves combining the starting material with effective amounts of (1) a urease producing micro-organism with a high urea hydrolysis rate; (2) urea; and (3) calcium ions, under standard conditions of 0.5-50 mM urea hydrolyzed min-1. Scientists found that after injecting the bacterial cementitious solution for a period of one month, the spores of three particular bacteria where still viable. Harmless bacteria such as Bacillus genus remains dormant until water enters the cracks. In this case, formation water, or water from fracturing fluids or any source can be used to trigger the bacteria. Moreover, the process does not require oxygenation.
In this paper, self-healing approaches based on bacteria will be thoroughly reviewed. The concept of biomineralization, bioclogging, and biorepair and its applications in improving the engineering properties of sands and cement is tackled. Based on the aforementioned aspects of self-healing in cementitious materials, recommendations for further research in self-healing engineering applications are proposed. This method is a green and eco-friendly way and the use of bacteria can lead to substantial savings. The following presents major practical applications for the oil and gas industry. Via the microbial calcification theory, solidifying the sea beds before drilling for oil, preventing hole cavings and wellbore enlargements or washouts, sealing undesirable leakage pathways near wellbores to achieve fracture plugging and permeability reduction, plugging sands to diminish water absorption and porosity are all lucrative potential applications the industry is in dire need of.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.
Wang, Yang (China University of Petroleum, Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum, Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Company Limited, Sinopec Shengli Oilfield Company) | He, Youwei (China University of Petroleum, Beijing and Texas A&M Univeristy) | Feng, Naichao (China University of Petroleum, Beijing) | Qin, Jiazheng (China University of Petroleum, Beijing) | Luo, Le (China University of Petroleum, Beijing) | Yu, Haiyang (China University of Petroleum, Beijing)
Yang Wang, China University of Petroleum, Beijing, and Pennsylvania State University; Shiqing Cheng, China University of Petroleum, Beijing; Kaidi Zhang, Lusheng Petroleum Development Company Limited, Sinopec Shengli Oilfield Company; Youwei He, China University of Petroleum, Beijing, and Texas A&M University; and Naichao Feng, Jiazheng Qin, Le Luo, and Haiyang Yu, China University of Petroleum, Beijing Summary It is well-known that water injection may induce formation fracturing in tight reservoirs. Especially when the field-geology condition is complex and the waterflood-induced fractures (WIFs) are not well-identified in time, the induced fractures can be of the same order as the well spacing, which has a significant, and generally undesired, impact on both areal sweep and vertical conformance. Therefore, the onset of WIFs must be identified in a timely manner, and the waterflooding performance must be evaluated comprehensively to formulate an appropriate strategy over time. A new work flow, containing analytical/semianalytical, statistical, and numerical techniques that are based on flow-rate/BHP and formation-testing data, is applied to identify the WIFs, diagnose waterflooding direction and front distribution, analyze interwell connectivity, and interpret abnormal bottomhole-pressure (BHP) behaviors in the Changqing Oil field. The work flow includes three modules: First, real-time monitoring and analysis, including modified Hall plot, evolving skin analysis, and injection/fracturing index methods, are used to identify the start of WIFs. Then, the formation-testing module, consisting of step-rate test (SRT), radioactivetracer logging, and passive seismic method, is applied to investigate the formation-fracturing pressure, and uneven waterflooding performance in the areal and vertical directions. On the basis of the two former modules, we adapt the third module, which includes injector/producer relationships (IPRs) and the constrained multiple-linear-regression (MLR) method, to quantitatively investigate the waterflooding direction by injection/production rates. A new model--injection well with waterflood-induced fracture (IWWIF)--is proposed to characterize the abnormal BHP behaviors considering the properties variation (shrinking fracture length and decreasing fracture conductivity) of WIFs during the falloff period. Compared with an individual method, the ITD (which is the abbreviation of WIF identification, formation testing, and dynamic production analysis) work flow is developed to obtain a comprehensive and deep understanding of waterflooding performance. The main emphasis of this study is to integrate different approaches to address the key uncertainties rather than analyze each data source individually. On the basis of the results obtained by this work flow, the operators can make a more-proactive and -reasonable decision on waterflooding management.
Gao, Qi (China University of Petroleum) | Cheng, Yuanfang (China University of Petroleum) | Han, Songcai (China University of Petroleum) | Yan, Chuanliang (China University of Petroleum) | Jiang, Long (China University of Petroleum)
ABSTRACT: Hydraulic fracturing treatments can efficiently enhance the well production performance in low-permeability reservoirs because of the improvement of communication between the formation and wellbores through created hydraulic fractures. In fact, not only the in-situ stress underground but also the pre-existed offset wells will influence the fracture propagation process. In this work, both experimental and numerical studies are carried out to investigate the hydraulic fracture propagation behavior under the effects of adjacent production and injection wells. First, laboratory tests were conducted to measure the rock mechanical properties. Based on the experimental results, we developed a new numerical model to simulate the growth of hydraulic fracture with production and injection wells located nearby. Furthermore, validation of the numerical model was verified by comparing the calculated fracture geometry with the experimental observation. The study shows that (1) the stress value and orientation will be gradually altered around the production and injection wells; (2) fracture prefers to propagate towards injection wells when production and injection wells co-exist, and the fracture propagation trajectory will not be affected in the cases that only production or injection wells exist; (3) the fracture will be shorter and wider when production and injection wells co-exist or only injection wells exist, and the effects on fracture geometry can be neglected when only production wells exist. The obtained results provide new insights for understanding the fracture propagation problem in the field scale.
Hydraulic fracturing technique has been widely used in the globe to stimulate low-porosity and low-permeability reservoirs with the aim of enhancing oil recovery. Thus, investigation of hydraulic fracture propagation behavior should be carried out with the objective of increasing the success rate during field operation. At present, a lot of researchers (Haddad and Sepehrnoori 2015; Kumar and Ghassemi 2016; Sobhaniaragh et al. 2016; Wu Kan et al. 2016; Gao Qi et al. 2017; Li Yang et al. 2017) are focusing on the simulation of fracture configuration during fracturing treatment. However, most of the work are completed under the assumption that pore pressure distribution is uniform and the direction of maximum and minimum horizontal stress are constant and orthogonal in the whole domain before fracturing the target well. In fact, the stress and pore pressure distribution in the formation could be much more complex as a result of the injection or production of fluid through pre-existed offset wells, which can affect the propagation path and size of fractures to some extent.
Liu, Rui (Ocean University of China) | Liang, Bingchen (Ocean University of China) | Pan, Xinying (Ocean University of China) | Wang, Lvqing (Ocean University of China, Navy Rearch Institute of P.L.A)
A porous sea-access road is required to connect the land and an artificial island for the offshore oil exploitation in the Yellow River Delta, China. The effects of a porous sea-access road on hydrodynamic characteristics and suspended sediment transport dynamics are investigated using a three-dimensional ocean model. The model results suggest that symmetrical eddies and the dipole structure of suspended sediment concentration variation occur around the construction. Compared with the traditional imporous sea-access road, the porous construction can diminish the effects on local circulations, sediment transport process and morphology evolution.
The Yellow River delta is one of the most important regions of petroleum production in China, where the second largest oil field in the country is located (Wang et al., 2005). A dike construction (hereafter referred as the sea-access road) is required to connect the land and an artificial island for the offshore oil exploitation. Meanwhile, this delta is a typical ecosystem of littoral wetland, providing key habitats for a variety of wildlife (Xu et al., 2004). The traditional imporous sea-access road could fundamentally block the local circulations and alter the topography and might profoundly exert even greater pressures on coastal ecosystems by threatening the fragile wetlands (Künzer et al., 2014). The development of sea-access road has been a source of socioeconomic and environmental conflicts (Bi et al., 2011).
The use of porous sea-access road provides a way to resolve the contradictions. Porous constructions are widely used in coastal engineering (Ma et al., 2014), which are not only environmentally friendly but also functional as well as the imporous constructions. A great number of numerical models have been developed to simulate the interaction between coastal flows and porous structures in the last few decades, for instance, Delft3D (Chatzirodou and Karunarathna, 2014), OpenFOAM (Higuera et al., 2015) and Truchas (Hu et al., 2012; Wu et al., 2014).
The exploitation of oil and gas fields which located in Bo Hai Bay has lasted more than half a century. The continued development of the oil and gas cause a lot of buried well head which bring hidden danger to the offshore operation.
Oil and gas field operators usually discard the well by strict technical procedures. The top level of well head should be 4m below the seabed base on the requirements of State Oceanic Administration (SOA). It is necessary to check the wellhead for safe when the well is filled with concrete.
In general, the wellhead is buried under the seabed deeply, so it has any effect on offshore operation. However when the time goes by the depth decreased due to washing on the seabed. Therefore it is still important to verify the position exactly in order to avoid the wellhead.
Side-scan sonar, magnetometer and other marine geophysical devices can be used to detect the exposed wellhead location on practical experience. Marine magnetometer is the only effective choice for buried wellhead.
This paper introduced a field magnetic test method and discussed the analyzes methods.
The well is cut and sealed by operators when oil production is shut down. Wellhead is buried below a certain depth of the seabed sediment. Buried wellhead usually brings more uncertain risk to offshore operation. For example, Buried wellhead may lead to many risks such as jack-up platform penetration failure, Bottom-Supported platform tilt, mooring force reducing etc.
Therefore, it is necessary to determine the location and depth of the buried wellhead by high-precision detection and analysis, which will provide the basis for the subsequent engineering practice.
At present, obstacles surveys are limited to above seabed. Marine survey equipment include multi-beam bathymetric system, side scan sonar, sub-bottom profiler, marine magnetometer and so on. It is difficult to detect the buried wellhead by side scan sonar and multibeam bathymetric system. To detect metal objects buried under the seabed, magnetometer and sub-bottom profiler are often used. Magnetic survey based on magnetic field strength principle and subbottom profiler based on acoustic principle. Magnetic survey and subbottom profiler survey are effective technique to search for buried pipeline. Few reports are available on buried wellhead detection.
The development of offshore heavy oil field need to reduce investment, energy consumption for oil and gas processing and transportation, we should improve the process, in order to simplify the process by using advanced technology, reduce processing facilities, improve equipment utilization, reduce energy consumption. This paper analyzes the current new technology of heavy oil processing in domestic and foreign oil field being used and in the test phase. The heavy oil in Bohai oilfield with viscosity reduction and experimental research, applied to Bohai heavy oil dehydration conveying process, as well as the feasibility and foreground of application in offshore heavy oil processing.
There is large and increasing proportion of heavy oil in oil and gas reserves in China and how to reduce the cost to maximize the heavy oil and super heavy oil production is the biggest problem facing China's petroleum industry. Onshore oil field has been using steam drive as the main development technology. The viscosity of degassed heavy oil at reservoir temperature is 10000 ~ 50,000 mPa. s, and super heavy oil (natural asphalt) more than 50,000 mPa.s. In recent years, China's offshore heavy oil development has been increasing. There have been new heavy oil field/ block put into production. How to reduce investment and increase economic benefits of heavy oil field is the focus of consideration. However, due to high density, high viscosity and poor fluidity it is difficult to achieve economic, safe and stable transportation.
Compared with the onshore oil field heavy oil reserve, the offshore heavy oil field well depth is relatively deeper, and there are more constrains on offshore platform space, equipment deploying, and Capex/Opex. Bohai heavy oil reserve is very large, well is deep, and characteristic viscosity range is wide. The oilfield is located in the Bohai Bay area, oil containing layers are mainly Qianshan, Guantao and Minghuazhen group, and crude oil viscosity range under reservoir conditions is 50 ~ 10,000 mPa - S.
Polymer flooding is one of the most broadly implemented chemical EOR processes due to its low injection cost and its success in prolific production increments. This work develops an artificial-neural-network based expert system by utilizing numerically generated training data using a high-fidelity numerical simulation model. Injection-pattern-based reservoir models are structured to establish the knowledge-base that serves for the ANN training. The injection process starts with water injection and switches to polymer injection when the water cut reaches to a threshold value. The chase-water is followed after a prescribed amount of polymer slug is injected. The expert system is generalized in terms of reservoir rock and fluid properties, rheological properties of the polymer solution, and critical engineering parameters to adjust to the complexities exhibited in the polymer injection projects. In developing the inverse model for project screening and design purposes, we have used an engineering design protocol employing inverse and forward-looking expert systems with the goal of exploiting the non-unique nature of the inverse problems. In this work, we employ the expert system as a forecasting and screening tool that is capable to predict time series based response in terms of oil production, water production and injection well sandface pressure data. The validity of the forward-looking expert system is confirmed via extensive blind test applications within a 5.83% error margin. More importantly, we present a project screening protocol that couples the expert system and particle swarm optimization (PSO) methodology to maximize the net present value (NPV) of polymer injection projects. In this way, we take the advantages of the fast computational speed of the ANN model to evaluate the finesses of project parameters. In the application of the inverse expert system, we observe that the proposed design protocol is capable to establish a catalogue of polymer injection design parameters that satisfy an expected hydrocarbon recovery performance. The work described in this paper exhibits the robust nature of the proposed expert system in adapting to strong non-linearities encountered in the polymer flooding projects. The coupled utilization of the inverse and forward-looking modules, enables the design engineers to find solutions that are unique to the problem being studied by simultaneously satisfying the imposed constraints effectively. The expert system proposed in this paper is one of the modules of a comprehensive artificial-neural-network based toolbox that includes a large spectrum of EOR processes.
Gao, Ming (State Key Laboratory of Enhanced Oil Recovery) | LV, Jianrong (Xinjiang Oil field Company) | Gao, Jian (State Key Laboratory of Enhanced Oil Recovery) | Zhang, Shanyan (State Key Laboratory of Enhanced Oil Recovery) | Wang, Qiang (State Key Laboratory of Enhanced Oil Recovery) | Wang, Xiaoguang (Xinjiang Oil field Company) | Chen, Lihua (Xinjiang Oil field Company)
The recovery factor of surfactant/polymer binary flooding field test in conglomerate reservoir is 14.6% now and it will reach to 18% by prediction. Nevertheless, it has not achieved good results in the early stage. Conglomerate reservoir is more complex and special. The method used in sandstone reservoirs can't be used directly in the conglomerate reservoir. In the early stage of SP flooding, the mature injection technique of sandstone reservoirs was adopted, but the phenomenon of high polymer concentration appeared.
The reservoir and porous characteristics of conglomerate reservoir was analyzed by intrusive mercury curve and pore throat distribution. The law of SP flooding was studied by micro experiment and nuclear magnetic resonance. Comprehensive analyses of SP flooding between conglomerate reservoir and sandstone reservoir were conducted, including SP flooding water cut, injecting SP pressure, time of polymer appearing in production fluid, producing polymer speed and incremental oil recovery. In order to find out the law of different type's reservoir moving, the casing logging analyses was carried out.
Due to the presence of the small grain between the large gravels, the distribution of pore and throat in conglomerate reservoir was characterized by two peaks. It was found that the remaining oil after water flooding was mainly in the pores with radius 1μm in the conglomerate reservoir.
Because of the existence of the macro pore path, the initial chemical flooding system had a rapid advance, and the effect was obvious seen after the profile control. The molecular weight of the polymer should be appropriately reduced according to the pore and throat sizes of the reservoir after the macro pore path were blocked by large molecular weight polymers. The matching relationship between polymer and reservoir was reestablished, and the molecular weight and injection concentration of the polymer were adjusted, and the effect of oil increasing was obvious.
The most significant new finding was that the SP system realized the utilization of 30-50mD reservoir by casing logging, which reduced the lower limit of SP flooding to 30mD. This is important because the reserves ratio of 30-50mD reservoir account for a large proportion in the conglomerate reservoir.
The SP flooding in conglomerate reservoir is different from the conventional chemical flooding. The novelty of this paper is to find the characteristics and appropriate adjustment method, which will provide the necessary support for future applications.