Guan-tao oil layer of Shu 1 Block in Liaohe oilfield is a medium deep and extra heavy oil reservoir, which has high porosity and high perm with edge water. In 2001, cyclic steam stimulation was applied with square well pattern and well-space 70m. After 9-10 cycles the stimulation development effect deteriorated and the degree of reserve recovery was only about 15%.To seek development method of extra heavy oil reservoir and improve the entirety recovery ratio of this block, after the feasibility research on SAGD technology in Guan-tao oil layer was finished, horizontal wells were infilled between vertical wells and 4 SAGD pilot test well groups combining vertical wells with horizontal wells were conducted Three cycles of cyclic steam stimulation to preheat the formation and decrease pressure were proceeded and the 4 well groups had produced for 1 year after converted to SAGD. Daily oil production capacity of single horizontal well increased from the initial 20-40t/d to 70-80 t/d after the multiple adjustment of the injection-production parameters. Preferable period effect was accomplished and the test provides good guide for same medium deep and extra heavy oil reservoir to change their development methods.
Survey of the test block
Block Du 84 locates on the middle of Huan-Shu structural belt of the western slope in the West Depression of Liaohe Basin. The Guan-tao oil-layer of Block Du 84 , shallowly buried ,is a thick blocklike extra heavy oil reservoir with high porosity , high perm to extra high perm and ,underscreen water??basal ground water and edge water. SAGD pilot test area lies in the north of Block Du 84(Figure 1). It is a monoclinal structure acclive to south-east and the structural dip is about 2-3 degree. No fault is found and its sands distribute continuously. The oil layer depth is 524-668m and the average net pay thickness is 91.7m, no basal ground water is found. The reservoir lithology was chiefly middle-coarse sandstone and inequigranular sandstone, average median grain diameter is 0.42mm. Reservoir quality is good ,the average porosity is 36.3% and average perm is 5.54µm2, average oil density under 20°C is 1.007 g/cm3, the degassed oil viscosity under 50°C is 23.191×104 mPa·s, resin and asphaltine is 52.9%, solidifying point is 27°C,paraffin content is 2.44%, the oil-bearing area is 0.15km2, geologic reserve is 249×104t, and the initial formation pressure is 6.02MPa.
Progress of the test
Based on the development condition and well pattern of extra heavy oil reservoir in Block Shu 1, and associating with the result of numerical simulation, SAGD pilot testing program concerning vertical and horizontal wells was drawn up. Four infilled horizontal wells named Guan-ping 10-- Guan-ping 13 were selected to form test well groups with around 34 vertical wells. The injector-producer distance is 35m, horizontal well spacing is 70m, horizontal segment size is 350-400m. What differs from in Canada is that the producing horizontal wells were infilled between the used vertical wells and below the vertical wells, 5m distance from the perforated intervals of vertical wells. The test from December of 2003 to June of 2006 was devided into two periods: steam huff and puff period to preheat the formation, SAGD producing period.
Cyclic steam stimulation period to preheat the formation
The pilot test block is a medium deep reservoir and the initial formation pressure is comparatively high. CSS has been applied in vertical wells for average 7.2 cycles before participate in preheat together and the recovery percentage was 12.7%. However, the formation pressure between wells didn't fall down too much. Because the horizontal wells are allocated between vertical wells where thermal connect doesn't exist and operation should be under low pressure condition during SAGD period, vertical wells and horizontal wells operate together during cyclic steam stimulation period to preheat the formation to achieve the condition help to convert to SAGD.
The leakage of hydrocarbon products from a pipeline represents not only the loss of natural resources, but also is a serious and dangerous environment pollution and potential fire disaster. So quick awareness and accurately location of the leak event are important to cut down the losses and avoid the disasters.
A leak detection method using transient modeling is introduced in this paper. This method is suitable for both gas and liquid pipelines with comprehensive consideration of the transient flow features of compressible flows and stochastic processing and noise filtering of the meter readings. The correlations for diagnosing the leak location and amount are derived based on the online real time observation and the readings of pressure, temperature, and flow rate at both ends of the pipeline. As an online real time system, great efforts have been paid to the stochastic processing and noise filtering of the meter readings and the models to reduce the impact of signal noise. It is essential too for the robust real time pipeline observer to have the self study and adjustment abilities in response to the large varieties of pipeline configuration, pipeline operation conditions, and fluid properties.
Real application cases are presented here to demonstrate this leak detection method. For example, in the leak detection of a crude oil pipeline of 34.5 km and F219mm, this method located the leak at 16.6 km from the pipeline upstream end which is only 0.6 km away from the actual leak location.
Keywords: leak, detection, gas, liquid, pipeline, transient, model
Much study has been conducted on the effects of formation Young's modulus and in situ stress on hydraulic fracture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controlling fracture height growth and that Young's modulus contrast is less important. However, a recent study pointed out that modulus contrast can have significant implications on fracture geometry and proppant placement.1 To expand on this topic further, we consider the combined effects of modulus contrast and in situ stress contrast on fracture geometry. A pseudo 3D (P3D) hydraulic fracture simulator with a rigorous layered modulus formulation is used in this study. The fracture height calculated based on uniform modulus versus layered modulus, under the same in situ stress contrast conditions, is compared.
The results are analyzed and explained, based on fracture mechanics fundamentals as well as the coupled fluid pressure effect in hydraulic fracturing. One important finding is that fracture height can also be contained by low modulus layers. The results from this study can be applied to hydraulic fracturing treatments in formations with moderate to significant modulus contrast. The mechanisms studied in this work could also partially explain some recent results from microseismic or tiltmeter mapping that show more fracture height containment than that predicted by commonly used P3D hydraulic fracturing simulators based on averaged modulus.
Since fracture height has been recognized as one of the critical factors that can determine the success or failure of a hydraulic fracturing treatment, many studies have been conducted on the effects of formation Young's modulus, in situ stress, fracture toughness, and layer interfaces on hydraulic fracture height containment in layered formations.1-9 Because of these studies, it is now well known that in situ stress contrast is the dominant parameter controlling fracture height growth and that Young's modulus contrast is less important. When studying different height containment mechanisms, modulus contrast is often considered separately from stress contrast to isolate the effect of each parameter. In reality, formation layers of different moduli are likely to have different in situ stresses7 and the contributions of both must be considered together.
With the development of tiltmeter and microseismic mapping services, more direct measurements or estimates of hydraulic fracture geometry have become available. It has been observed that sometimes the fracture is more contained in height than is predicted by simulators. Some new mechanisms and explanations have been given, including the "composite layer effect,?? "shear dampening,?? and fracture behavior at layer interfaces, for the unexpected height containment.6,10,11
On the other hand, more advanced numerical models have been developed for hydraulic fracture simulators,1,12 and the combined effect of height containment mechanisms can now be studied with fewer approximations for hydraulic fracturing conditions. The study of the layered modulus effect has been investigated using a finite element method that can rigorously account for different moduli in a hydraulic fracture simulator.12 Two effects of high modulus layers on fracture height containment were provided and explained. The shortcomings of using an averaged modulus were pointed out by comparing simulation results of averaged modulus with that of layered modulus.
To expand further on the shortcomings of using an averaged modulus, we consider the combined effect of modulus contrast and in situ stress contrast on fracture geometry and show that modulus contrast can have a significant effect on fracture height. Height growth can be contained by low modulus layers because of different mechanisms than those already discussed in the literature for high modulus layers.1
In this paper, fracture height containment mechanisms are briefly reviewed. A parametric study using a hydraulic simulator that rigorously accounts for variable modulus12 is conducted for various combinations of stress contrast, modulus contrast, and fluid viscosity. The results are analyzed and the reasons for limited height growth are explained based on fracture mechanics fundamentals and the coupled fluid pressure effect in hydraulic fracturing.
High cycle stimulation in Henan heavy oilfield has been suffering the problems such as low formation pressure, much accumulated water which deadly influence the steam thermal efficiency, leading to a bad production recovery. In high temperature, SEPA solution can decompose out gas that can increase the elastic flooding energy, compounding with special surfactant and alkaline, SEPA can develop steam conformance and flooding efficiency. Laboratory tests show that the recovery of non-homogeneity core has been increased by 16.5 percent point. This technology has been used more than 120 wells in Henan oilfield and effective rate reach 92.5percent. It has been proved that the injecting well has a bigger peak daily output, longer valid period and a significant increment of production.
Since high steam cycle came in He'nan heavy oilfield, steam huff and puff has become main stimulations, up to Dec. 2003, average 8.3-cycle time in the individual well, and maximum to 25 periods. Low formation pressure and high-accumulated water rate has deeply influenced the steam thermal efficiency (STE), so as to bring about bad results. Previous surfactant injection such as heavy oil flushing agent and thin film spreading agent also produced little effect because the formation situation was getting worse and worse. How to improve current stimulations and how to enhance STE for high-cycle time in the old heavy oilfield, has became urgent research task.
Critical Analyses for Restricting STE in Mid-Later Stage
After surveying heavy oil recovery technology at home and abroad, as well as current situations in Henan heavy oil thermal recovery, based on deficient wells' reservoir features and performance, three things account for as follows:
High Formation Accumulated Water Rate. After multi-cycle steam injection in wells, more and more condensed water of steam trapped near the wellbore. The more cycle time, the high underground accumulated water rate. According to statistical data, the back-production water rate (BPWR) in the deficient wells kept between 16 and 60 percent. High-accumulated water rate can result in STE decreased; water period extended, and output deeply declination. Also vicious circle appeared in steam injection and water recovery [1,2].
This article presents the stability research of latex tenacity cement slurry, develops the BCT series stabilizer and studies the performance of the slurry and the set cement. Due to the slurry performance study, it is found the latex material can be evenly distributed in the slurry, which can form a film to bond free water and micro particle, reduce fluid loss and prevent gas migration. Adding other additives to this system, the slurry shows better performance with lower fluid loss, better rheological behavior and adjusting thickening time. Due to the set cement performance study, it is found the latex particle can evenly fill in the fine gap of C-S-H gel. It assembles and forms a film to cover the CSH surface, which can decrease the set cement elasticity coefficient and permeability, improve its impact resistance and anticorrosive properties. Moreover, the application of this latex tenacity cement slurry system is introduced in this article.
In oil exploration and production cementing is an important procedure of drilling. The cementing quality directly affects the recovery efficiency and lifetime of oil and gas well, which have attracted more attention. Excellent cement slurry system is essential to cementing improvement.
Latex slurry, referring to the slurry with some latex is a good cementing slurry, which has many advantages such as low fluid loss, anti-gas migration and good rheological property, meanwhile its set cement also has performances such as high compressive strength, good tenacity and anti-corrosion. Styrene-butadiene latex (SBL) system is a main embodiment product.
The Performance of Latex Slurry
Due to the emulsification of emulsifiers, the latex particles evenly distribute in a latex solution with a thermodynamic metastable condition. When effected by polar ions, vigorous mechanic agitation and large temperature fluctuation, its stable structure will be destroyed. The latex particles will aggregate and flocculation happens. In latex slurry, the mixing medium is a slurry. The multivalent cations as Calcium ion, magnesium ion and aluminium ion dissolving out of a slurry, together with other polar groups of the slurry additives, can break the chemical stability of a slurry. The shearing force during the mixing and pumping process presents challenge on the mechanic stability of a latex, meanwhile, the low storage temperature and high well temperature also call for high thermodynamic stability for a latex.
To increase the latex stability, it is necessary to design its particle structure. By introducing strong hydrophilic carboxyl groups to distribute on the latex particle surface, the CSBL latex shows higher chemical stability than that using physical absorption emulsifier. By adjusting the emulsifier concentration and its radio to monomer, controlling latex particles size and their distribution, the latex emulsion, which has soft core and hard shell structure, can be prepared to improve its impact resistance and temperature tolerance. A special Emulsifier BCT-830L, which matches with carboxylic styrene butadiene latex, can shield cement high valence ions influence, further improves the latex stability and is used to prepare the product BCT-800L, which contains the above emulsifier and the latex.
The thickening tests at 40?*0.1MPa and 100?*60MPa for the slurries formulated with CSBL and with BCT-800L are performed respectively to determine the latex stability in a slurry. The test results are shown in table1. The results show that slurry with a low co ntent CSBL will flocculate at high temperature. If increasing CSBL content, the slurry shows unstable and flocculates at atmosphere pressure thickening test. The slurry with BCT-800L containing the special emulsifier, can endure high temperature, high pressure and mechanic agitation, showing good stability. Moreover, BCT-800L concentration increasing doesn't influence the stability of a slurry.
Fluid Loss control and Rheological property
The effects of latex BCT-800L concentration on slurry fluid loss are shown in Fig. 1. The results show that fluid loss gradually lowers down with latex concentration increasing. When latex concentration reaches 10%(BWOC), the API fluid loss is well controlled less than 100mL . If latex concentration reaches to more than 15%(BWOC), the fluid loss can be controlled within 50mL. With the help of other fluid loss additives at a small quantity, API fluid loss can be controlled within 30 mL.
Zhang, Jianguo (Baker Atlas) | Yu, Mengjiao (U. of Tulsa) | Al-Bazali, Talal (Baker Atlas) | Ong, Seehong (U. of Texas Austin) | Chenevert, Martin E. (U. of Texas Austin) | Sharma, Mukul Mani (Baker Hughes Drilling Fluids) | Clark, David Erle
Wellbore instability, particularly in shale formations, is regarded as a major challenge in drilling operations. Many factors, such as rock properties, in-situ stresses, chemical interactions between shale and drilling fluids, and thermal effects, should be considered in well trajectory designs and drilling fluid formulations in order to mitigate wellbore instability related problems.
A comprehensive study of wellbore stability in shale formations that takes into account the 3-dimensional earth stresses around the wellbore as well as chemical and thermal effects is presented in this work. The effects of borehole configuration (e.g. inclination and azimuth), rock properties (e.g. strength, Young's modulus, membrane efficiency and permeability), temperature, and drilling fluid properties (e.g. mud density and chemical concentrations) on wellbore stability in shale formations have been investigated.
Results from this study indicate that for low permeability shales, chemical interactions between the shale and water-based fluids play an important role. Not only is the activity of the water important but the diffusion of ions is also a significant factor for saline fluids. Cooling drilling fluids is found to be beneficial in preventing compressive failure. However, decreasing the mud temperature can be detrimental since it reduces the fracturing pressure of the formation, which can result in lost circulation problems. The magnitude of thermal effects depends on shale properties, earth stresses and wellbore orientation and deviation.
Conditions are identified when chemical and thermal effects play a significant role in determining the mud-weight-window when designing drilling programs for horizontal and deviated wells. The results presented in this paper will help in reducing the risks associated with wellbore instability and thereby lowering the overall non-productive times and drilling costs.
Super-high pressure gas fields in Tarim Oilfield mostly lie in the area of Tianshan mountains. the upper cap rock of these gas fields is salt gypsum formation which is deeply imbedded, this salt gypsum formation contains not only many different pressure systems but also soft mudstone and salt-water bed with super-high pressure, 80 percent of all accidents and complex situations take place in this section. Tarim Oilfield arranges well Dina-11 in Dina structure in order to change this adverse situation; all results and achievements during drilling operation are as follows:
Consummate the drilling technology for Shanqian structure and reduce the possibility of accidents and complex situations, quicken the speeds of exploration and development through drilling operation in well Dina-11
Dina area as a main anticipative reservoir of Tarim Oilfield also lies in the structure of Tianshan mountains(Fig.1), as mentioned earlier. It exists great difficulty and risk in drilling operation in this area too. For this reason, Preliminary prospecting well Dina 1 and well Dina 2 arranged earlier in this area were one after the other blowout out of control for drilling accidents.
Well Dina 1, was starting drilling operation in 1999. When the well was drilled at 4440.2m with drilling fluid which density was 1.52g/cm3 on July 14th, 2000. The pump pressure rised from 17.2MPa to 38.1MPa,the safety latch in mud pump was cut. Then, the drill stem was stuck, the upper/down kelly cock and valve in standpipe could not be closed. Eventually, blowout had to performed through this rout way of kelly ?standpipe? kill line manifold? relief line ,the density of ejective brine is 1.24 g/cm3, Cl- is 199000mg/L.The salt crystal block the drill stem. For this reason, this well was abandoned with cement injection at last.
After well Dina 1, Well Dina 2 started drilling operation in 2000.When the well was drilled at 4875.59m with 1.85 g/cm3 mud on April 29th,2001.The kick occurred, after well shutdown, the shut-in casing pressure was 16MPa and the shut-in standpipe pressure was 14MPa.Afterward,the choke valve which installed in the choke manifold was opened up and discharged fluid in hole. Then, shutting in the well again, the caing pressure was 33MPa and the standpipe pressure was 27MPa. During kill operation with fracturing truck,the casing pressure went up 66MPa,the well-control equipment was failed and led to bolw out and fire. After subsequent wrecking and fire fighting operation in 66 days, kick-killing succeed finally.
The use of the ensemble Kalman filter (EnKF) appears to be a promising approach for data assimilation and assessment of uncertainties during reservoir characterization and performance forecasting. It provides a relatively straightforward approach to incorporating diverse data types including production and/or time-lapse seismic data. Unlike traditional sensitivity-based history matching methods, the EnKF relies on a cross-covariance matrix computed from an ensemble of reservoir models to relate reservoir properties to production data. For practical field applications, we need to keep the ensemble size small for computational efficiency. However, this leads to poor approximations of the cross-covariance matrix and loss of geologic realism through parameter overshoots, in particular by introducing localized patches of low and high permeabilities. This difficulty is compounded by the strong non-linearity of the multiphase history matching problem. Specifically, the updated parameter distribution tends to become Gaussian with a loss of connectivities of extreme values such as high permeability channels and low permeability barriers which are of special significance during reservoir characterization.
We propose a novel approach to overcome these limitations by conditioning the cross-covariance matrix using information gleaned from streamline trajectories. Our streamline-assisted EnKF is analogous to the conventional assisted history matching whereby the streamline trajectories are used to identify grid blocks contributing to the production response of a specific well. We then use these grid blocks only to compute the cross-covariance matrix and eliminate the influence of unrelated or distant observations and noisy calculations. We show that the streamline-assisted EnKF is an efficient and robust approach for history matching and continuous reservoir model updating. Our approach is general, suitable for non-Gaussian distribution and avoids much of the problems in traditional EnKF associated with instabilities, overshooting and the loss of geologic continuity during model updating. We illustrate the power and utility of our approach using both synthetic and field applications.
This paper will present the development novel temperature control viscosity acid (TCA) technique that uses for acid fracturing in Ordovician formation in TZ region of TARIM, China. The Ordovician formation in TZ field is extreme heterogeneous carbonate with naturally fractures, that locates in deep underground of 5000-6300m, the reservoir temperature is around 120°C-145°C, and the reservoir close-fracture pressure The above 90Mpa.During the past decade, many acid fracturing techniques (such as gelled acid technique and emulsified acid technique) have been applied, but the results were not satisfactory. Under these difficult circumstances, in order to gain perfect acid fracturing effectiveness, we have succeeded in developing TCA acid fracturing technique.
A new TCA system is presented in this paper that has unique viscosity-temperature characteristic, the TCA viscosity is the same as gelled acid at room temperature, and increase rapidly while under high temperature reservoir conditions, the TCA viscosity can come to over 200mPa.s. It is a preferable retarded and little leakoff acid system, at 120°C, TCA's rock/acid reaction rate is 6.3 times and 2.4 times slower than straight acid and gelled acid respectively.
This paper also provides two TCA acid fracturing cases in the Ordovician formation in TARIM, the results are remarkable. one of the wells (well A), The production was used with choke of 12.7mm after acid fracturing. The tubing pressure was 37MPa. Production was 72.7×104m3/d of gas and 485m3/d of oil. That demonstrates that TCA can generate longer etched fractures in heterogeneous carbonate reservoir.
Acid fracturing is one of the effective stimulations of the oil-and-gas wells in carbonate reservoir. The production enhancement of a well after acid fracturing treatment is affected by the length of the etched fracture that remains open after the treatment and the conductivity of the fracture, and then is affected by the performance of the acid fluid and fracturing techniques. Wherein, fracturing techniques depends mainly on fracturing equipments, therefore in the same reservoir and with the same techniques, the effectiveness of acid fracturing treatment is mostly determined by the acid system.
At the present time, gelled acids are usually used for low permeability carbonate reservoir. However, at the high temperature of the carbonate formation, the gelled acid has a viscosity of no more than 10 mPa·s, and so it has a high acid-rock reaction rate and large volume acid leakoff, which leads to short effective length of the etched fracture. It reduces the chance of discovering new formation in test wells and the effectiveness of stimulation in production wells. There is a need for modified or new acids with the benefits of high viscosity at high reservoir temperature, low acid-rock reaction speed, and little leak-off volume, so that the acid can have improved acid penetrating capability, high conductivity of fracture which can connect the remote natural fractures and channels.
The Preparation of TCA
1. Introduction of the TCA Technique
Now acid fracturing and hydrofracturing are the main stimulation techniques for low permeability carbonate reservoir. Four in five fracturing are acid fracturing in which the acid used are mainly conventional hydrochloric acid, gelled acid, emulsified acid and leak-off controlling acid (LCA). Gelled acid usually losses its capability at high temperature. For example, a gelled acid has a viscosity of 30~50 mPa·s at room temperature, while in a formation over 120°C, it has only no more than 10 mPa·s. At the same time, the gelled acid has a serious leak-off problem, especially in a heterogeneous carbonate reservoir. H+ has a big mass transfer coefficient and the acid-rock reaction rate is high in this acid. Therefore the acid penetrating capability in formation is limited seriously. Emulsified acid has the similarly problem which leads to a large frictional resistance, limited delivery volume and limited penetrating distance in formation.
Using virtual reality technology to build the scene of big scope and many scenery , it exist the question of network bottleneck and drawing difficulty when WEB browses.
For this question , according to rules of Virtual Reality Modeling Language, we make the big scene effective division and layered attemper and capability optimization.
The effective division means partition a big scene into several small rectangle scene pieces ,every scene piece all can run alone and the easy and smooth operating on WEB, thus realizes that the scene is partitioned effectively .The layered attemper means using the node in the VRML ,realized the scenery model in the scene piece delamination load by step. the scene piece Again conformity and whole attemper .The capability optimization means adopting reducing number of subsection, Instances and text compression methods etc. Carrying on the scene capability optimizes. Thus realize that the big scene is run on WEB.
Uses the above technology to have accomplished big scene development work in " virtual history of No.8 Production Plant " system, that is runing. The realization of this technology, for show the large-scale virtual jointly station and oilfield templet engineering on the net in future etc, all have the very important meaning. Establish the technology foundation for forges " Digital Oil Field ".
Applying virtual reality technique on the WEB browsing to establish large range, multi-vision scenes Oil Field infrastructure has networking bottleneck and mapping difficulty problems. In order to employ the VRML to represent large range of scenes on the Web visualization, based on characters of VRML scenes files, we separate the large range scenes efficiently following the VRML rules, and then control scenes loading by distance achieving stratification activation, and the last, optimize its performance. It has been resulted that VRML scenes files are optimal and minimal implemented in local machines. Therefore, it achieves large range of scenes on the Web visualization.