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Collaborating Authors
International Oil and Gas Conference and Exhibition in China
Abstract Slag MTC is a unique cementing technique that drilling fluid is converted to cement slurry with the addition of blast furnace slag. By controlling slag activating speed and colloid content in MTC slurry, Slag MTC not only has the properties which meet the requirements of normal cementing jobs, but also shows the advantages slurry in rheology, transition time of static gel strength, settlement stability, volume shrinkage and compatibility with drilling fluid. After using slag MTC in 130 wells, we can say this technique not only can get good quality of cement job in normal wells but also is very useful for solving the problems of gas migration in high pressure well and poor quality in small clearance in directional wells and lost circulation in low pressure well. 100% of cement job were successful among these 130 wells. The authors described the advantages of this technique in solving cement problems of complex wells and analyzed the properties of slag MTC. Three cementing cases in typical wells are presented. Introduction MTC techniques have been studied for half a century, among which only slag MTC and Portland cement MTC make sense and have been used in drilling operations. Many cases show that slag MTC can not only improve the quality of cement job, but cut cementing cost. Cement engineers in China have concerned slag MTC since early 90's. Some research institutes and oil fields have set to study MTC techniques. So far, Studies on slag MTC have made good progress and this technique has achieved success in field application. Drilling Research Institute of CNSPC (China New Star Oil Company)has launched study on MTC since 1992 and already developed a whole set of techniques. Slag MTC has been successfully used in 130 wells in Chuanxi, Linpan, Huabei, Songnan, Subei and Tahe Oil fields. The achievements in slag MTC are listed as follows:Polymer mud, positive ion gel mud, brine mud and positive ion gel oil mud can be converted to slag MTC. The lowest mud weight is 1.03 kg/l and highest 1.92 kg/l. The shallowest well is 850m and deepest 3900m. Slag MTC has been used to cement surface, intermediate and production casing. Slag MTC slurry is pumped with normal cementing truck or on-site mud pump. Success rate of cement operations reaches 100%. The quality of cement meets the requirements of production and stimulation, e.g. fracturing operation. The earliest formed slag MTC cement around production casing has kept intact for 6-year production. Slag MTC cementing can cut cost by 5โ38% compared with conventional cementing.
- North America > United States > Texas (0.28)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.24)
Recovery Area and Reserves Increment by Tapping the Potential of Regions beyond the Oil-Water Transition Zone
Ren, Yulin (E&D Research Institute of Daqing Oil Field Company) | Lin, Ying (E&D Research Institute of Daqing Oil Field Company) | Ma, Chengdou (No. 3 Oil Production Plant of Daqing Oil Field Company) | Wang, Qingxia (E&D Research Institute of Daqing Oil Field Company)
Abstract Through analysis on transitional zone and extending pilot area in Daqing oil field, oil and water distribution regularity, formation development status of transitional zone and extending area are studied in this paper, clarifying the extending potential of the pilot area. The problem of crude oil out flow during development in transitional zone is comprehensively studied, rational water injection pressure limit in transitional zone is provided by combining numerical simulation, the extending development principle of transitional zone is concluded, all these would provide theoretical basis and practical experience for guiding the extending and potential tapping of transitional zone. Introduction Daqing oil field is composed of five oil fields, i.e. Lamadian, Sabei, Sazhong, Sanan, Xingbei, Xingnan, since its development from 1960, relatively good development result has been achieved. But development of transitional zone is mainly limited within internal band, external No.3,4,5 bands were not totally developed, with undeveloped transitional area of as high as 70.18km, accounting for 22.5% of transitional area. The undeveloped transitional area would be larger if plus NO. 5 band and the extending area resulted from downward movement of oil-water contact. In order to clarify the feasibility of extending development in transitional area, extending pilot areas in five transitional zones in representative Sabei, Xingnan, Sazhong oil fields etc. are set up in sequence, Fig.1 is the extending well location map in transitional zone in Xingnan oil field, 58 extending wells are drilled in form of profile in the 5 pilot areas, with extending distance of 700โ1500m. extending potential of transitional zone is clarified through investigation such as well drilling, oil test etc. Geological Characteristic of Extending Area in the Transitional Zone Fine geological study is conducted in transitional zone and extending area, clarifying formation developing characteristics of the transitional zone. The developed formations in undeveloped area in transitional zone of Daqing oil field are mainly Sa I, Sa II oil formation group in north part and Sa?oil formation group in south part, Sa III and Pu I oil formation group developed in part of blocks. High permeable, thick belted distributary channeling sandstone dominated in north part of oil field, with distributary channeling sand thickness accounting for 50โ70% on the water; relatively homogeneous thin outer front sheet sand dominated in south part of oil field, with outer front sheet sand thickness accounting for 50% or so. Drilling rate of Sa I, Sa II oil formation is mainly at 70โ95%, the development is relatively good on the whole. From statistical result of formation areal map and drilled sandstone thickness of each band in different area, it can been seen that formation development performance of transitional zone and extending area is almost the same, so, variation in formation thickness in extending area of transitional zone is mainly controlled by formation structure and oil water contact, locally lithology deteriorating also have certain influence on formation thickness. Oil water distribution characteristics of extending area. Determination of oil water contact in extending test area in the transitional zone. Currently used oil water contact value was determined at initial stage of oil field development, which had certain difference with actual value due to little amount of data and conservation etc. at that time, so oil water contact was re-determined according to watered out layer interpretation data, oil test data etc. Fine geological study is conducted in transitional zone and extending area, clarifying formation developing characteristics of the transitional zone. The developed formations in undeveloped area in transitional zone of Daqing oil field are mainly Sa I, Sa II oil formation group in north part and Sa?oil formation group in south part, Sa III and Pu I oil formation group developed in part of blocks. High permeable, thick belted distributary channeling sandstone dominated in north part of oil field, with distributary channeling sand thickness accounting for 50โ70% on the water; relatively homogeneous thin outer front sheet sand dominated in south part of oil field, with outer front sheet sand thickness accounting for 50% or so. Drilling rate of Sa I, Sa II oil formation is mainly at 70โ95%, the development is relatively good on the whole. From statistical result of formation areal map and drilled sandstone thickness of each band in different area, it can been seen that formation development performance of transitional zone and extending area is almost the same, so, variation in formation thickness in extending area of transitional zone is mainly controlled by formation structure and oil water contact, locally lithology deteriorating also have certain influence on formation thickness. Oil water distribution characteristics of extending area. Determination of oil water contact in extending test area in the transitional zone. Currently used oil water contact value was determined at initial stage of oil field development, which had certain difference with actual value due to little amount of data and conservation etc. at that time, so oil water contact was re-determined according to watered out layer interpretation data, oil test data etc. Determination of oil water contact in extending test area in the transitional zone. Currently used oil water contact value was determined at initial stage of oil field development, which had certain difference with actual value due to little amount of data and conservation etc. at that time, so oil water contact was re-determined according to watered out layer interpretation data, oil test data etc.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Conventional well test interpretation is dominated by the analysis of pressure BuildUp (BU). The method for analyzing BU is derived by the principal of superposition based on the constant terminal rate DrawDown (DD) solution of an "infinite" reservoir with uniform properties. The presentation of the diagnostic plot (log-log plot) and flow regime identification from the pressure derivative curve - in the Late Time Region (LTR), in particular, critically rely on time functioning. The most popular time functioning used for well test analysis is Horner and Agarwal equivalent time. However, these time functioning methods are not reliable for the LTR analysis. When linear (semi-infinite fluvial channel or compartmentalized systems) and pseudo-steady-state flow (finite or closed system) are present, the flow regime diagnostic at LTR using Horner or Agarwal equivalent time frequently result in a false definition of flow regime and misleads the analyst. The de-superposition method can present the pressure BU in the same way as that for a DD, so the ambiguity in identifying the LTR behavior can be resolved. On the other hand, the DD LTR behavior (pressure derivative) in semi-infinite or finite reservoir systems is very valuable for the identification of the reservoir external boundary conditions (even though it is usually not good to define the radial flow region due to the rate fluctuation and often, incorrect production history input). Experience has proved that BU analysis using the de-superposition method combined with DD LTR analysis can provide much more confident well test analysis. In this paper, two field examples conducted in the fluvial gas reservoirs in the Gulf of Thailand have been interpreted in this way. At first, one of the tests has been analyzed using the conventional method by ignoring the DD. Then, the examination of DD LTR and the analysis of pressure BU using de-superposition method have been conducted to show where analysis was wrong in the first approach. Following the same procedures, the second test has been interpreted to further demonstrate the value of de-superposition method in analyzing test conducted in reservoirs with limited extent. Introduction Gas reservoirs in the Pattani Basin, Gulf of Thailand were formed in fluvial depositional environment (Fig. 1). Economic gas reserves were discovered at a reservoir depth from about 8100-ft โ 9800 ft. of Tertiary fluvial channel sand. The field is highly affected by normal faulting. Numerous discontinuous reservoirs exist in fluvial sands within a thick Miocene succession. The reservoir compartments are relatively small, and DST tests are often dominated by LTR boundary response because of the limited reservoir size. The analysis of well tests conducted in the area often show linear flow and pseudo-steady-state flow (reservoir depletion), which confirmed that the tested reservoir blocks are either semi-infinite or finite extents. Within a DST testing period, DD can capture the LTR response nicely in these reservoir systems due to their smaller size. But the following BU often missed this signature because it needs at least one and a half to two times of the preceding DD duration to be able to identify such boundary response. In practice, this requirement can not be always satisfied due to the economic and operational reasons. One of the main objectives for well testing during the field appraisal stage is to estimate the reservoir productivity. This can be achieved by stabilising radial flow during the test. The analysis of the radial flow period will give the formation flow capacity as well as the permeability. However, it's impossible to extract such reservoir parameter by analyzing DD due to the difficult in identifying the radial flow regime/period on the pressure derivative curve. This has been resulted from the rate fluctuation and phase segregation of high velocity gas during flowing period.
- Asia > Vietnam > Gulf of Thailand (0.24)
- Asia > Thailand > Pattani > Pattani (0.24)
- Asia > Thailand > Gulf of Thailand (0.24)
- (3 more...)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- (2 more...)
Abstract Adsorption/desorption and precipitation/dissolution are thought to be the two major mechanisms operating in the retention and release of scale inhibitor in squeeze treatments in an oil reservoir. The general nature and extent of the scale inhibitor adsorption process is determined principally by the equilibrium isotherm, although the shape of the inhibitor return curve may be significantly modified by kinetic effects for a specific squeeze practice. For a precipitation squeeze process, the solubility of the inhibitor-calcium complex and the rate of dissolution are currently thought to be two main factors that govern the return curves in our computer modelling studies. Experimental coreflood techniques can be used to provide inhibitor breakthrough profiles and these effluent concentration data can then be used to derive isotherms for the adsorption systems or to test the validity of the above precipitation mechanisms. This paper presents results from a series of flow rate varying adsorption and precipitation laboratory corefloods for a penta-phosphonate (DETPMP) and a poly-carboxylate (PPCA). This experimental data is the most complete and accurate ever produced and is of a quality that allows us to test the details of the above mechanisms. A general analysis and discussion of the adsorption isotherm derivation is provided and modelling results for the non-equilibrium adsorption corefloods are reported. The significance of these results for field applications is discussed. Introduction In a scale inhibitor squeeze treatment, the interaction between scale inhibitor and rock system is either through an adsorption/desorption or a precipitation/dissolution (phase separation) mechanism. Adsorption of inhibitors is thought to occur through electrostatic and Van der Waals interactions between the inhibitor and the formation minerals. Precipitation inhibitor squeeze treatments were originally proposed as a method of extending the squeeze lifetime beyond that obtained in an adsorption treatment of the same generic scale inhibitor. For such processes, the main inhibitor retention mechanism within rock formation is thought to be due to the formation of sparingly soluble calcium/inhibitor complex. The complex may be in the form of an actual solid or a separate gel-like liquid phase. To achieve longer squeeze life times from the existing inhibitor products or the potential ones under development, a better understanding of the mechanisms controlling the retention and release of the inhibitors is obviously very important. The environment into which the chemical is to be injected must also be fully appreciated. On this basis, computer modelling tools can be developed to provide an insight into the processes occurring in squeeze treatments, and eventually to allow the analysis and design of improved squeeze treatment designs.
- Europe (1.00)
- North America > United States > Texas (0.68)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract An extensive experimental study on friction pressure drop for nonNewtonian drilling fluids in pipe and annular flow was conducted. A fully instrumented 350 feet flow loop, consisting of two pipes and two annular flow test sections, was used in the test program. Five different muds were tested, which included: Bentonite mud, MMH mud, polymer mud, Glycol mud and Petrofree vegetable oil mud. The experimental data obtained were used to generate very useful plots of "friction factor" versus "generalized Reynolds number". For each of the mud systems, the plots offer a practical and accurate means in determining needed friction factors for the calculation of pressure drops in pipe and annular flow. In addition, a comparative discussion is presented on measured friction pressure drop data, predicted by correlations such as the power law, Bingham plastic and yield power law. The importance of wall roughness on turbulent flow friction pressure drop calculations is also investigated. Introduction The prediction of friction pressure losses is very important during drilling operations. The concern is that inaccurate prediction of the friction pressure loss can cause inaccurate engineering decisions that may cause drilling problems such as loss of circulation, kicks, improper rig power selection, etc. These problems become more significant in the area of slim hole drilling. Generally, when a drilling fluid flow behavior deviates from the simple Newtonian, friction pressure loss predictive equations become more complex and less accurate due to many simplifying assumptions. It is believed that one factor that may contribute to the inaccuracies in friction pressure loss calculation in drilling is the particular rheological model used in the development of a given empirical correlation or theoretical expression. The rheological models that are thought to represent the flow behavior of drilling muds are the Bingham Plastic, the power law and yield power law. Not knowing which model may best represent a given drilling mud type in the prediction of friction pressure loss motivated this study. Literature Review Many publications appear in the literature that deal with the flow of nonNewtonian fluids through pipes and annuli. However, experimental data in regard to these fluids are almost non-existing. Drilling muds are nonNewtonian fluids and thus several rheological models have been proposed to describe their flow behavior. The most commonly used in the drilling industry are the Bingham plastic model and the power law model. Due to its complexity, the yield power law model did not receive as much use. Hanks et.al. (1963) have published a paper on flow of fluids with yield stress. He used the Bingham plastic model to predict laminar and turbulent transition for fluids with yield stress. They proposed a general criterion for the onset of turbulence. Hanks has also published a number of papers on concentric annular flow of fluids. Langlinais et. al. (1985) studied friction pressure losses for gas and drilling mud. They have used different equivalent diameters and their effects on single phase flow of drilling mud in concentric annulus.
- Research Report > New Finding (0.71)
- Research Report > Experimental Study (0.71)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Development and Field Application of PDM with Double Bent Housing for Sidetracking Medium-Short Radius Horizontal Wells
Su, Yinao (Research Institute of Petroleum Exploration and Development of CNPC) | Cheng, Zuxi (Research Institute of Petroleum Exploration and Development of CNPC) | Tang, Xueping (Research Institute of Petroleum Exploration and Development of CNPC) | Wang, Xinmin (Directional Well Service Company, Liaohe Petroleum Administration)
Abstract Sidetracking through casing window is an effective measure for developing old oil fields. Medium-short radius, as known as intermediate, horizontal well is required to produce the residual oil in the original well network for short landing point displacement. 5LZ95ร7.0TW double bent housing PDM with build-up rate between 30ยฐ/30m and 45ยฐ/30m has been developed to meet the concrete requirement of sidetracking through window milled in 7" casing in Liaohe oilfield. The design physical parameters of the PDM are determined, and double bent housing structure is adopted through analyzing its passing capability through casing, the performance of BHA and predicting the build-up rate. 5LZ95ร7.0TW PDM is easy to manufacture, repair and maintain, and the drilling string is easy to run through casing, and its build-up rate can be predicted accurately. The field application of the PDM in two wells of Liaohe oilfield demonstrated that it fully reached its design purpose. It is superior to single bent housing PDM jointed with a bent sub, and is welcome to users. Introduction Horizontal wells can be divided into four basic types: long radius(K< 8ยฐ/30m), medium radius (K=8ยฐ~20ยฐ/30m), medium-short radius(K=0.7ยฐ~3ยฐ/m), short radius (K=3ยฐ~10ยฐ/m) in terms of the curvature of their wellbore trajectories. Medium-short radius horizontal well has advantages of short control section, small TVD error, ease of hitting thin oil layer, and is often used to sidetrack old wells. Medium-short radius horizontal well sidetracking technology is an effective approach to reducing cost and raising benefit by sidetracking horizontal wells to exploit the residual oil and improve the ultimate recovery. PDM for medium-short radius well is different from that for long, medium radius well in its high bent angle or double bent housing causing high build-up rate(0.7ยฐ~3ยฐ/m), and its small size(F120.65~88.9mm)i.e. low rigidity while used in drilling old wells. One of the crucial parts to develop medium-short radius (curvature radius=82~20m) horizontal well sidetracking technology is to design and select small size bent housing PDM to meet the requirement of build-up rate. It is very important to design such PDM that can meet the features of sidetracking medium-short radius horizontal well and requirement of its build-up rate, and is easy to run into casing, use, repair and maintain. Based on the equivalent relation of PDM structure and theoretical foundation of mechanical analysis, prediction and sensitivity analysis of build-up rate, and the passing capability analysis of PDM through casing, a 5LZ95ร7.0 double bent housing PDM which meets the requirements of field application has been designed and manufactured. Equivalent Relation of Structure of Double Bent Housing PDM and Single Bent Housing PDM Single bent housing PDM and double bent housing PDM are often used in horizontal well drilling. Through analyzing the equivalent relation between them, it's found that a geometrical equivalent relation exists between them (Fig. 1).
- Asia > China > Liaoning Province (0.45)
- North America > United States > Texas (0.34)
Abstract Blowout or uncontrolled flow of an oil well involves complex flow phenomenon involving transient multiphase flow and heat transfer in the wellbore. Various wellbore and reservoir parameters govern the maximum velocity attained in a given well. The maximum velocity may be either critical (sonic) or subcritical. This work adapts a transient model to capture the events leading to the onset of maximum velocity of a fluid mixture. The model uses a numeric method to solve the mass, momentum, and energy equations for the wellbore, and an analytic approach for fluid flow in the reservoir. The theoretical sonic velocity computed by assuming isentropic expansion turns out to be higher than the actual maximum velocity attainable in the well. Computational results also show that the assumption of isentropic expansion becomes progressively worse with increases in gas/oil ratio, because of increased frictional loss. Among various parameters, the blowout rate increases with increased well- productivity index, flow-string diameter, reservoir pressure, and gas-oil ratio (GOR). The probabilistic reservoir-simulation approach is used to answer the reservoir-fluid-loss question. Introduction Unrestricted or uncontrolled flow of pressurized fluids from a pipe or a well is commonly termed blowout. The main concerns with blowout of an oil well are the danger of gas-oil combustion, leading to possible damages to equipment and wellhead, jeopardizing personnel safety, and the serious environmental effects of the expelled fluids. In addition, loss of reserves can have significant economic implications in certain cases. Most relevant studies address kick detection and blowout control. Only a few deals with actual control of blowout, using dynamic-kill operations. Of these, only Fan et al. presented a transient model to do the necessary calculations. Others used wellbore hydraulics following the steady-state approach. Perhaps the Clark and Perkins study remains the most comprehensive to date. The primary mechanism governing a blowout well is the rapid, near-surface liberation and subsequent expansion of large amounts of dissolved gas. Increased free gas results in higher mixture velocity with consequent increase in the total pressure gradient owing to higher friction and kinetic energy losses. The reduced fluid pressure leads to lower fluid density and further increase in velocity and pressure loss. As the fluids accelerate to the surface, the available flowing pressure limits their speeds and corresponding flow rates. If fluid pressure becomes sufficiently low, the velocities of the fluids will reach the critical (sonic, choking) velocity of the mixture. Under this condition, the pressure at the wellhead is termed the critical discharge pressure. For a number of reasons, the blowout rate can be less than the critical value. For example, surface restrictions at the wellhead or relatively low-reservoir potential could lead to a blowout where the fluid velocity is below its critical value. In this case, the wellhead pressure will stabilize at a value higher than the critical pressure and the sonic discharge velocity will not be reached. Computation of fluid flow and pressure profile in those cases must account for the interaction between the expelled two-phase fluids and the atmosphere. In this paper, we will concern ourselves only with cases where two-phase flow stabilizes at the critical condition. Analysis of a Blowout The critical (sonic) velocity represents the maximum speed fluids may attain. The reason for this limitation lies in the inability of rarefaction wave-fronts, which is the pulse traveling down the wellbore, to propagate in a direction counter to that of the flow. In other words, the sonic velocity of these downstream-traveling-pressure pulses is balanced exactly by that of the upstream-traveling fluids. If critical flow is reached, it must stabilize such that the sonic condition is established at the wellhead, while subsonic flow occurs beneath the wellhead.
- North America > United States > Texas > Permian Basin > Clark Field (0.89)
- North America > United States > Louisiana > Perkins Field (0.89)
Abstract A computer package, HCPT, which has been developed provides a useful tool for the field engineer to make prediction and analysis of the drilled cuttings transport in drilling inclined well to assure efficient hole cleaning during operations. It has been designed to allow the user to calculate the cuttings bed formation, determine whether the bed slides upward or remains stationary and analyse the position of the cuttings bed formed and the height of the cuttings bed layer. It has been programmed using Visual Basic and will be performed as an executable file in the Windows system environment. This user-friendly computer package has been developed on the basis of the theory that authors established. The theory contains a new mathematical model, which enables the simulation and prediction of cuttings transport in highly deviated to horizontal wells taking account of operating parameters, wellbore geometry, fluid properties and cutting characteristics. A three-layer model for cuttings transport and some equations for cuttings concentrations have been included. Introduction One of the primary functions of the drilling fluid is the transport of drilled cuttings out of the hole. Over 18 years or so, considerable efforts have been expended on solving this problem in inclined to horizontal wells. The methods by these investigators can be categorized into two main approaches: an empirical and theoretical. The simulating limitation of those is still existed because of very specific range of operating empirical conditions and based on simplified theory. Therefore, a few mathematical models can only simulate a limited range of phenomena observed in laboratories. This work has developed a new mathematical model, from which the set of equations are derived and a numerical solution is proposed. By analyzing the mechanism of cuttings bed formed in inclined wellbore, a three-layer model for cuttings transport has been established, and some relative equations including cuttings bed height and cuttings particle settling velocity have been obtained. They give the method of how to determine when the cuttings bed will be formed and what kind of formed cuttings bed it is. Considering the situation that drilled cuttings have gone through the different angle hole sections, the cuttings concentration should not be the same in each of hole sections of the inclined well. The equations of cuttings concentration are available. The motion of the moving bed layer formed in inclined wellbore is controlled by the critical velocity of the moving bed layer, which has been derived from the equation of cuttings bed force balance. In order to accomplish the three fields above, the parameters in annular fluid flow such as flowrate, velocity profile, pressure gradient and apparent viscosity are required. Some equations that have to be numerically solved have been derived from the basic equations of fluid mechanics and boundary conditions. Model Development Calculation of the Basic Parameters. The theoretical models require an accurate description of the rheological properties of the fluid and determination of velocity and apparent viscosity profiles in the annulus of the borehole. Bingham-Plastic rheological model is as follows:Equation (1) In order to obtain the velocity profile model for annular fluid at different pipe rotary speeds and pipe eccentricities, some flow equations must be derived from the equations of motion and continuity, and assumptions are made regarding the fluids and boundary conditions. Calculation of the Basic Parameters. The theoretical models require an accurate description of the rheological properties of the fluid and determination of velocity and apparent viscosity profiles in the annulus of the borehole. Bingham-Plastic rheological model is as follows:Equation (1) In order to obtain the velocity profile model for annular fluid at different pipe rotary speeds and pipe eccentricities, some flow equations must be derived from the equations of motion and continuity, and assumptions are made regarding the fluids and boundary conditions.
- Asia (0.93)
- North America > United States (0.93)
Abstract In the period of maturing oil field development, on one hand, water saturation becomes higher and higher, on the other hand, lots of moveable oil still stays in the reservoir. The main reason for this case is determined by the variation of the reservoir, so the main job for geologists is to know the heterogeneity and continuity of the reservoir. In this case, the well spaces are about 200-300 meters. In order to give a relatively reliable prediction of the reservoir variation between wells, we must build a prototype model and know the real condition of the reservoir. During the past 5 years, we have studied the fan-delta outcrop and built a very detailed prototype model and established sets of geological knowledge databases, which include lithology database, microfacies database, sandbody scale database and many geological statistic databases. According to these useful databases, we can predict the heterogeneity and oil saturation of maturing oilfield in different blocks and different layers. A few wells have been drilled according to our prediction through prototype model, and the oil saturation is 5-7 times higher than the old wells. Prototype model is very useful in the oilfield reservoir heterogeneity prediction, which have the same or similar depositional environment. In order to predict the reservoir variation of different depositional reservoir, series of prototype models must be built. Introduction The content of establishing geological knowledge database developed at the same time with the foundation of geology and especially the reservoir geology, it becomes more complete and perfect along with the other disciplinary continuous development. But the conception of geological knowledge database was shaped from the content studied by geology and its research achievement only decade ago. As we know, the direct subsurface information received from drilling core and the indirect information from the logging record amount to only tiny percent of the total formation volume. Seismic explanation can describe the 3-D characteristics of reservoir in theory. But the vertical resolution can't satisfy the development. In this situation, to predict the 3-D characteristics of reservoir from the finite data, geologists must establish detailed reservoir geological knowledge database about such type of depositional system and depend on it, a practicable reservoir prediction method. So, the construction of reservoir geological knowledge database is basic for underground reservoir precise prediction between wells in oilfield and is also the key to establish accurate geological model. The reservoir geological knowledge database is referred to the general parameter that generated and derived from the multitude of researches which can quantitatively and qualitatively express the geological characteristics of different genetic reservoir units and can predict the similar sedimentary system. It can be used to guide the researching, predicting and modeling of studying reservoir. For example, the shape of different genetic units is a qualitative geological knowledge database; and the W/T ratio of channel sandbody is a quantitative geological knowledge database. The methods to require geological knowledge database is numerous, but the most important are the detailed research from the outcrop, modern deposition and the dense well pattern in oil field. The outcrop is much superior to other methods for constructing the geological knowledge database because of its distinguishing features.
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.88)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (0.54)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.54)