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Collaborating Authors
Well & Reservoir Surveillance and Monitoring
Abstract Producing experience in complicated, dispersed small oil and gas fields in the west peripheral area of Daqing oilfield has led to development of a system of progressive production technology. Experience shows that this technology system is feasible and of good practical value to the production of a complicated small oilfield. Introduction Complicated oil and gas fields have following characteristics, multiple oil-bearing strata, stacked traps of many types, and complicated relationships between oil and water both vertically and horizontally. It is impossible to develop complete knowledge of complicated reservoirs in a short period of time. Profitability is enhanced if the oil and gas-bearing reservoirs, which are best understood and have the better productivity are developed first. During formal production stage, various advanced prediction and completion technologies should be used and the all oil and gas accumulations should be developed, connected and deeply understood. New series of oil-bearing strata and traps should be developed by stages. This kind of development is called progressive production, and a whole set of technology based on it is called progressive production technology. In recent years, by applying progressive technology, we have developed five oil and gas fields in the west peripheral area of Daqing Oilfield (Fig. 1). Based on the production example of Aogula Oilfield, this paper gives a summary and review for the gradually developed and perfected progressive production technology. Overall Arrangement Of Progressive Production Before deciding to conduct progressive production in a complex oil and gas field, systematic study, evaluation and analysis must be made. Overall arrangements must be determined by fully using available exploration data. Progressive production in Aogula Oilfield started in 1988. According to the evaluation of detailed exploration in 1985, this oil field could be divided into four areas. (Fig. 2). On the west side of the Aogula major fault they are, Ta 20 well area, Ta 5 well area, and Ta 3 and Ta 301 well areas. On the east side of the Aogula major fault there is the Ta 2 well area. The main part of the field is on the west side of the major fault, with 77.1% of the OOIP of the whole oil field. For the three areas on the west side of the major fault, from north to south, the geological conditions become more complex. The prospecting degree of the north Ta 20 well area was relatively high. At that time, three information wells had been drilled. Many layers with large thickness had been penetrated and single well productivity was relatively high. The vertical distribution of oil, gas and water was recognized relatively clearly. In the middle Ta 5 well area, there was only one exploration well, which suffered from mass channeling as a result of a bad cement job.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract The production profile can be obtained with a continuous flow meter and a gradiomanometer. Slip and other factors in the vertical string for two phase (oil-water) flow, affect the data and make it very difficult to interpret. To solve this problem, studies were made in a simulation well of the relationship between the rotary speed of the spinner and the water holdup, and the ratio of the apparent velocity to the average fluid velocity and water holdup. Four relationship charts and interpretation programs were developed. A total model of the simulating experiment was built, which can interpret multiple zone oil/water production rates to draw their profile map, and quantitatively interpret oil bubbles moving upward, and interpret the reverse rotation of the spinner in the vertical string. The data obtained from 20 wells show that the method has high resolution so that low producing layers can be detected and quantitatively interpreted. Also, intra-formational interpretations for thick formations can be made. In conjunction with the water intake profile of the surrounding injection well, a plot of water-injection versus oil-production can also be drawn. Introduction Daqing Oilfield has entered into the stage of high water cut. To maintain high and stable production rate, the reservoir producing situation must be known. A satisfactory fluid production profile can be obtained with a continuous flow meter and a gradiomanometer under the conditions of the two phase (oil-water) flow. Compared with inflatable and station measurements, continuous measurement has many advantages. The upper limit for flow rate is over 1000 m3/d. Logging speed is high and repeat runs can be made. The log data are reliable and can reflect the intra-formational changes of a thick formation. However, there is some slip between oil and water as the two-phase flow moves vertically, so changes in the flow behavior are very complicated and the data interpretation is very difficult. Thus, a study of interpretation methods of two-phase (oil-water) flow was conducted. Test procedure and test result for oil water two phase flow A test for two-phase (oil-water) flow was made in a simulation well. The test media are diesel fuel and water. The tools used in experiment are a spinner flowmeter and a gradiomanometer. Water holdup, Yw, is derived from an average density measured with the gradiomanometer and spinner count, CPS, that is obtained from a continuous flowmeter. Since Daqing oil field has entered into the stage of high water cut, the water holdup in the borehole is generally greater than 50%. Thus, a holdup of more than 40% was selected for the study. Experiments were conducted in two modes, station measurement and continuous measurement. For different water cuts, different flowrates were selected. 27,000 data points were obtained and four charts were generated in this experiment. To determine water cut, Kw, Figure 1 shows the relationship between the spinner count and different water cuts. Figure 2 shows that the relationship between the ratio of the apparent velocity to the average fluid velocity and the water holdup. The velocity measured in the borehole is an apparent velocity, Va, that is the response to the flowrate of the fluid which is covered with spinner. With a measured water holdup, Yw, and apparent velocity, Va, average flowrate Ut1 can be found from Figure 2. Figure 3 shows the relationship of the spinner count (CPS) and the average flow rate, Ut2, under the condition of the continuous measurement. The curved form and changing trend of Figure 3 is generally consistent with similar data obtained with station measurements. The average flowrate obtained from the stationary measurements is Ut3. The spinner response is a negative value when water cut is lower than 40% and flowrate is about 30m3/d. An average fluid velocity Ut can be derived by averaging over Ut1, Ut2, and Ut3. Mathematical model and computerized interpretation program The figures mentioned above were generated with a computer using an empirical formula to fit the experimental data. The computer plotter can automatically plot the apparent velocity regression curve of every station and list the multiple or separate-zone oil and water production profiles. Based on the empirical formula, a mathematical model was build to simplify the multiple element regression as a single-element regression combining various related variables and using them to form new variables. 1. Modeling g(Q, Yw, CPS)=0 the relationships among Q, Yw, Kw, CPS are as follows:
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
The Logging Technology for Determining Production Profiles Through Casing/Tubing Annulus in Pumping Wells
Zhang, Baoqun (Daqing Petroleum Administrative Bureau) | Zhang, Shuying (Daqing Petroleum Administrative Bureau) | Wang, Baochun (Daqing Petroleum Administrative Bureau) | Zhang, Weiping (Daqing Petroleum Administrative Bureau)
Abstract Logging technology for determining production profiles through casing/tubing, the small diameter series of designing tools, and the advanced logging techniques is described. Applications of the logging technology are demonstrated using typical examples. Introduction In Daqing oil field, the scientific research works for the production well logging have successfully solved the problem of the logging in pumping wells. A full set of logging techniques have been developed for lowering the tools into a pumping well through the casing/tubing annulus without the logging cable getting tangled. Eight different kinds of inflatable and noninflatable small diameter logging tools have been developed. Truck-mounted digital logging instrumentation (Type SKSD.-94) is used. For logging interpretation, we developed quick processing software, which runs on the surface truck-mounted computer. A systematic analysis program is used at the computer center. The above research results compose a perfect through annulus logging equipment system and a logging quality control system which meets the needs of the oil/water two-phase and oil/gas/water three-phase surveys and provides data processing for the pumping wells producing 0.3 to 250 m3/d of fluid with water cuts between 0 and 100%. The technology is ready for use at wellsite. At present, the logging capacity is about 2000 runs per year. The logging provides the main data for reservoir evaluation including determination of the production condition of each pay zone, determination of the oil/water distribution and formulation of the injection and production adjustment programs. In the recent years, the logging technology for determining production profiles in pumping wells has provided the basis for designing and implementing the field development. Other means of monitoring performance monitoring will not take the place of logging technology. Logging Condition Rotary Eccentric Wellhead Equipment. Rotary eccentric wellhead equipment must be installed for measuring the production profiles in pumping wells. With this equipment, the tubing is positioned against the inner wall of any side of the casing; creating a crescent-shaped path in which the logging tools can be lowered and raised. The eccentric tubing hanger is installed on the top flange of the casing head through a locating bearing. Installed in this way, the tubing hanger can be easily turned if the subsurface logging tool string becomes tangled or stuck. If the logging cable gets wrapped around the tubing string, the relative position of the tubing string in the crescent-shaped path can be changed to free the tool. The offset well head used in Daqing oil field provides a very convenient way to release wrapped logging cable. The Requirements of Logging Path and Downhole Tools. The casing commonly used in Daqing oil field is 139.7 mm (5 1/2 in.) casing. In pumping wells, 63.5 mm (2 7/8 in.) tubing is used. The maximum distance between the pump barrel and casing wall is only 34 mm, a very narrow path for a logging job. The OD's of the logging tool strings are 28 mm and 25 mm, respectively. To lower the logging tool strings into a pumping well through the pump barrel/casing annulus freely and to prevent the tool string from hitting the tubing collars, the vertex angle of the tool head is designed to be 12 . The Requirements of the Tubing String and Producing Conditions. An audible alarm unit was installed on the tubing string and to set a production regulator in the casing string. The OD of tools installed on the tubing string is less than 90 mm. The tubing string must be smooth and the metal parts must not be permanently magnetized. The first tubing joint must be a complete one and a cone guide must be installed at the bottom end. The lower end is positioned 5 m above the top of the oil-bearing formation.
- North America > United States > Texas > Fort Worth Basin > Overall Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Daqing Oil Field is the largest oil field in China and one of the largest oil fields in the world. Development began 35 years ago. By cyclic identification and comparison of continental heterogeneous sandstones, studies on sedimentation models and sand body types, a better understanding of the development stage, water flood characteristics and residual oil distribution of different types of sandstones was obtained. A whole set of technologies (including geology, reservoir engineering, drilling, production, open hole logging and production logging) were developed to increase the recoverable reserves of different zones. As a result, at each stage of development the recoverable reserves of the oil field were increased. It is estimated that after drilling the third round of infill wells and after polymer flooding, the recoverable reserves will be 118 to 133% higher than 1978. Daqing was brought on production in 1960. The present water cut is around 80%. Production reached 50x10 in 1976 and in 1995 reached a record high of 56x10. Production has been stable for 20 years and is estimated to be stable for another long period of time. Excellent development results have been obtained and are better than planned. Introduction The Daqing Oil Field reservoir facies are sandstones of continental origin. Compared with marine sediments, there are many more payzones, and the zones are thinner and are very heterogeneous. Consequently, the development technologies used for marine sandstone oil fields could not be used without major modifications. The geologic characteristics and challenges encountered in the development of Daqing, necessitated development of a whole set of technologies (including geology, reservoir engineering, drilling, production, open hole and production logging). These technologies lengthened the stable production period and increased the recoverable reserves of the oil field. Summary Daqing Oil Field is located in the middle of the depression of the Songliao Basin on a secondary structural belt. It is an elongated anticline with a surface area of around 1,000km2. North to South the distance is around 117km, and East to West the distance is 6 to 23 km. Maximum enclosure height is 524m, and the structure is quite flat. The structural angle at the East and West is about 1 to 4 degrees. There are seven local high points in this oil field and each has its own name (Fig. 1). When the structure was formed, there were some medium to small faults with a displacement of 30 to 80 m, and length of 1 to 3km. These faults basically do not compartmentalize the oil and water distribution of the field. It has a uniform oil and water contact plane and belongs to a single hydrodynamic system. The main pay zones are Early Cretaceous and are river, deltaic and lacustrine sandstone sediments. From top to bottom they are divided into S, P and G zones. They can be divided into more than 200 sandstones and 138 sandstone bodies (not including thin zones less than 0.2m). During deposition, the water level of the lake changed many times, forming many sandstones with different configurations, thicknesses, cyclic characteristics and physical properties. The sands are highly heterogeneous both vertically and horizontally, and form a very complex system. The pay zone section is divided into many layers of intercalated sandstones and mudstones. Excluding sandstones thinner than 0.2m, there are more than 130 single sand bodies in the northern part of Daqing. The thickest ones are more than 10 m, and the thin ones less than 0.2 m. The average thickness about 2 to 0.5 m (Table 1a). The permeability ranges from 10x10-3 m2 to 3,000x10-3 m2. The porosity ranges from 2 to 30%. Oil saturation is 60 to 80%. In general, the permeability, porosity and saturation of the thick layers is higher and thin layers is lower. The sandstones are mainly oil wet, but those at the bottom and southern part of the structure are more water wet. Daqing crude has a paraffin content of 20 to 30%, pour point of 25 to 30 C, and sulfur content less than 0.1%. The original gas oil ratio (GOR) was 40 to 45 m3/t. Saturation pressure is 6.4 to 11 MPa, crude density is 0.85 to 0.89, and in the formation crude viscosity of 6 to 10 mps. Salinity of formation water is 5,400 to 9,400 mg/L. Daqing Oil Field was discovered in Sept. 1959 and development began in 1960.
- North America > United States > Louisiana > Fields Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.94)
Abstract Currently, the vapor pressure of crude oil is primarily controlled through Reid Vapor Pressure testing (ASTM D323-90) from both a commercial product and environmental air emissions standpoint. Environmental regulations do require a further estimation of the "True" crude oil vapor pressure from the Reid test results via a nomograph relationship contained in API 2517. The true vapor pressure of a given oil or fluid is of interest because it defines the point of vapor initiation (i.e., the boiling point or bubble point). The quantity of such oil vapors is of course directly related to product losses and environmental air emissions. However, the MITRE Corporation in support of the Strategic Petroleum Reserve Crude Oil Quality program has found the Reid test even in combination with the API 2517 adjustment for "True" vapor pressure to give 50% to even 300+% errors in the determination of a crude oil's actual true vapor pressure. MITRE therefore developed a test method and calculation algorithm that substantially improves the determination of a crude oil's "actual" true vapor pressure. The method involves use of a device to 1) analyze the composition of gas separating from a liquid oil stream at a known pressure and temperature, 2) measure the rate of gas and oil flow exiting the same gas/oil separator, and 3) use the described test data in an iterative calculation algorithm with industry- established gas/liquid equilibrium values to estimate the crude oil's vapor pressure within +/- 2% (or 0.3 psia). This test method provides a characterization of the oil's composition which allows prediction of vapor pressure and even air emissions quantification over the full temperature range of interest. In addition air toxics existing in the oil (H2S benzene, etc.) have been quantified to the 10 ppm level in the oil as well as in the evolved gases. Introduction The Strategic Petroleum Reserve (SPR), which maintains the nation's emergency supply of oil in the event of an international oil crisis, has developed several sites for underground storage of oil in salt-dome-leached caverns. The underground oil storage volumes are subject to natural gas intrusion and geothermal heating. Both gas and temperature rise can cause the vapor pressure of crude oil to increase to the point that oil vapors will be generated upon subsequent oil depressurization into atmospheric storage tanks. The SPR oil drawdown rates of over 1 million barrels per day (MMBD) per site and the SPR's unique storage system subject to gas and heat intrusion created a need for an accurate vapor pressure test method, since significant safety and environmental impacts are associated with evolved gas volumes of even less than 1 SCF/BBL for such large crude oil flowrates. Background At MimE's initial involvement in the SPR "gassy/hot" oil issue, there was a contradiction between Reid test results, which after adjustment by the API 2517 nomograph (Figure 1), indicated that the 'True" vapor pressure of the oil was less than atmospheric, and other tests conducted in the lab such as bubblepoint and gas/oil ratio tests which indicated that the oil's bubblepoint (or vapor pressure) was greater than atmospheric and that vapors were evolving from the oil when depressured to atmospheric pressure. Note that the vapor pressure of a liquid is defined as the point at which the liquid begins to form a vapor phase (bubbles) due to either a temperature increase or a pressure decrease. Since the vapor pressure of a liquid is closely associated with the initial formation of gas bubbles, the terms vapor pressure and bubblepoint are often used interchangeably.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.90)
- Government > Regional Government > North America Government > United States Government (0.74)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (2 more...)
Abstract This paper describes field implementation of a new production method, the water drainage-production system for oil fields with bottom water coning problems. The method enhances the production rate of water-free oil while eliminating hydrocarbon contamination of produced water. The new method was used in a Wilcox sand in North Louisiana to resolve the problem of excessive water cuts experienced in conventional wells. Typically, for a conventional well in this area, a water problem would develop in 60-90 days after the beginning of oil production. The excessive water cut would cause a reduction of the oil rate from 35 BOPD initially to 12 BOPD with 97% water cut. In this application a new well was drilled through the oil and water columns and dual- completed in both zones. The water-drainage completion (gravel packed) was isolated from the oil completion with a packer and 3-1/2" tubing. A downhole progressive cavity pump lifts the water in the tubing, while the formation pressure drives the water-free oil up the annulus between the tubing and 7" casing. To date, after 12 months of production, the oil production rate is averaging 45 BOPD, water-free. Mathematical modeling was used to help in the design of the completion. Shown in this paper is a computer-generated analysis of the drainage-production system's performance. The analysis helped to determine the oil and water rates and geometry of the well's completion. Chemical analysis of water produced in the new method shows minimal contamination with polynuclear aromatic hydrocarbons (PAH), 11 parts per billion. This is an over 50-fold reduction compared to PAH contamination of water produced conventionally. Also, no contamination with oil and Grease was measured with a detection limit of 2 mg/l. Introduction A major environmental concern of oil production is the associated saltwater that is produced in water drive reservoirs. This problem is very evident in an offshore environment where saltwater discharge must meet NPDES requirements for maximum contamination with hydrocarbons.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Mississippi > Merit Field (0.99)
- North America > United States > Louisiana > Nebo-Hemphill Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.90)
Abstract We discuss local grid refinement procedures for reservoir simulation, including local timestepping, which means the use of different time step sizes in the coarse and refined regions. A non-linear multigrid algorithm is proposed for solving the coupling between coarse and fine meshes. This approach does not need to solve for matrices with complex structure, it does not employ any relaxation parameters, it is well suited for parallel processing and it can be easily implemented in existing simulators. The proposed techniques were implemented in a black-oil simulator and tested in complex problems described in the literature. The results show the ability local grid refinement has to model the behaviour in the vicinity of wells. The coupling algorithm has shown to be robust and efficient, allowing a significant reduction in CPU time when compared to regular and fine meshes. The local timestepping procedure has shown to be attractive specially in cases where the number of grid blocks in the coarse mesh is large when compared to the refined regions. This situation is typical of field studies. Introduction In numerical reservoir simulation, it is often necessary to model processes restricted to a small portion of the reservoir, such as coning behaviour. A natural way to reach this objective is through the use of local grid refinement, which has been intensively researched over the last decade. When this technique is employed, however, irregular connections among the grid blocks appear and an efficient solution of the resulting non-linear equations remains a challenge. In this work, local grid refinement procedures for reservoir simulation are investigated, which distinguish from others published in two main aspects:–the algorithm employs a non-linear multigrid technique for the resolution of the coupling between the refined regions and the coarse mesh. Such procedure does not need to solve for matrices with complex sparsity pattern, it is well suited for parallel processing, it can be easily implemented in any existing reservoir simulation code and, unlike some of the domain decomposition algorithms, it does not need any relaxation parameters; –the discretization allows for local timestepping, using different time-step sizes for the coarse and refined meshes. Our algorithm has been implemented in the PETROBRAS' in-house black-oil simulator. Test problems, close to the daily engineering practice, have shown the ability locally refined in space and time meshes have to reproduce the results of uniformly fine ones. The algorithm for solving the coupling between the coarse and fine regions, together with the local timestepping technique, has revealed to be robust and efficient even for difficult problems. Discretization Of The Flux Equations We consider as our basic mesh a block-centered cartesian grid. Over it, we place finer cartesian meshes in the regions where a greater resolution is needed, in such a way that a fine block is always contained in a coarse one (its father). We associate a time step size t to the basic mesh, while in the refined regions a sequence of smaller time step sizes can be used. We consider a fully implicit scheme in our composite mesh based on a finite volume technique, which originates a conservative discretization. The scheme is obtained in a similar way to that of Ewing et alli. for linear parabolic problems. Theoretical stability and convergence results are presented in Ref. 14. The discretization of the reservoir flow equations is based on their space-time integral over each grid block. The grid blocks in the composite mesh will be divided in four groups:–unrefined blocks: those in the basic mesh with no neighboring refined block. Their discretization is the usual seven point operator one, with mobilities calculated in a upstream way; –refined blocks: those in one of the refined regions with no contact with the coarse mesh. The same discretization applies, although one has to write a balance equation for each of the intermediate local time steps; –refined blocks in the boundary: those in one of refined regions in contact with the coarse mesh. Suppose that ijk are the coordinates of one of these blocks, while IJK are the coordinates of its father and that the i+1/2, jk is the edge in contact with the coarse mesh (Fig. 1).
- North America > United States (0.47)
- South America > Brazil (0.35)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.41)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (0.34)
Summary This paper describes an integrated reservoir study performed to select a location for Maraven's first horizontal well in Lake Maracaibo, Venezuela. A depleted reservoir producing for 40 years, and with over 80% of its recoverable book reserves produced, was selected to place the horizontal drainhole. The field has been yielding high watercuts since 1975, ranging from 85 to 95%, and vertical new wells would water out within weeks. The reservoir study used a synergetic approach from a team composed of Petrophysicists, Geologists, Sedimentologists and reservoir engineers, from both the operator and the service company, aimed at choosing the reservoir and the best location within it. The selected reservoir has a dip of 30 degrees and leans against one of the major faults defined in the Lake Maracaibo basin. Introduction The VLA 8, C-7 reservoir, of mid eocene age, has contributed over 42 MMSTB of oil to the volumes produced by Maraven in Lake Maracaibo, in western Venezuela (Fig 1). Reservoir calculations have revealed an OOIP of about 118 MMbbls, and a recovery factor of 42%. With an estimated producible oil volume of 50 MMSTS, an additional 8 MMBbls are still to be produced from these accumulations. VLA-8 is a longitudinal reservoir leaning against one of the major and better defined faults in the Maracaibo basin, the Icotea Fault. It is divided in two zones, according to the structure, one, known as El Pilar, towards the eastern boundary, characterised by low dips (2 to 10), whereas the other presents higher dips (30-45) as it encounters Icotea, and is known as The Attic. (Fig 2) The field was originally put on production in 1954. By the end of 1958, four wells drilled in the area were contributing close to 9.7 Mbopd. Water was produced from the beginning. By 1960 the average water cut of the reservoir reached 20%, and production rates from the wells were still held high, from 3 to 6 Mbopd. The period elapsed from 1970 to 1981 saw a production decline from 6 to 2 Mbopd, mainly due to water production, which peaked at 45% in 1970. A study published in 1982 pointed out the possibilities of water cusping between the main line of producers, parallel to Icotea.
- South America > Venezuela (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Q01a-Ondiep License > Block Q01 > Helder Field > Helder Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Q01B-Ondiep License > Block Q01 > Helder Field > Helder Formation (0.99)
Abstract Most of the work on variable rate-variable pressure tests that is available today is related to single-phase systems. The purpose of this study is to examine variable rate-variable pressure tests (VRT), during the transient period, considering multiphase flow effects in the reservoir for solution gas-drive systems. The only procedures present today to evaluate VRT run under multiphase flow conditions use either pressure drop, pressure squared, or pseudo pressure function. The first two approaches are empirical in nature and their use is restricted. The direct use of pseudo pressure approach is more general but it requires the availability of representative relative permeability data. This paper presents methods that permit the determination of the mechanical skin and sandface effective permeabilities. These methods are derived from the pseudo pressure function but they require only traditional information, i.e. rate and wellbore pressure versus time. The expressions developed in this study are useful for both single-phase and solution gas-drive systems. Synthetic and field data are analyzed to illustrate the use of the techniques developed in this work. Rate normalization, using pressure and pressure squared drop, and the use of superposition principle are analyzed, and their advantages and limitations under multiphase flow conditions are compared to the methodology presented in this study. Introduction Up to date the majority of studies on well test analysis with variable rate-variable pressure tests have used the assumption of single-phase flow, using a deconvolution or convolution process based on the superposition principle. Recently, several papers have appeared on multiphase flow analysis. Some of these works consider a constant sandface oil rate, others use a constant bottomhole pressure condition. References 20 and 21 use the p-squared approach to analyze variable rate tests taken under multiphase flow conditions. The p-squared method is based on the hypotheses that the transmissivity is proportional to pressure which is not necessarily satisfied for all cases. The purpose of this study is to introduce procedures to obtain reservoir parameters from VRT data, in solution gas-drive systems, using the pseudo pressure function as a basis, without assuming an specific relationship between the integrand of the pseudo pressure and pressure. In Refs. 8-16 it is shown that it is possible to correlate solution gas drive responses during the transient and boundary-dominated flow periods with the liquid solution. Based on this result a practical method is proposed, to compute the mechanical skin factor and estimates of sandface effective permeabilities for the transient period. In general, for multiphase flow it is not possible to correlate well responses with liquid flow solutions, in terms of conventional parameters. Specifically, for variable rate production during transient flow period, one can not use rate normalization of pressure drop and we do not know if Duhamel's principle with wellbore pressures can be used to compute absolute formation flow capacity and mechanical skin factor. This paper is divided in three parts. In Part I, the numerical model used in this work is briefly described and the rate functions, imposed as boundary conditions to generate the synthetic results, are presented. In Part II, a background is established for the findings presented in this paper. Also, procedures available in the literature to analyze VRT under multiphase flow conditions are presented in this section. In Part III, new procedures devoted to the obtention of the mechanical skin factor, s, and estimates of effective sandface permeability are introduced. SPE 35276, Supplement to SPE 26961, is available as a supplementary document.
Abstract A semi-analytical model for the production interference of multiple reservoirs sharing a common aquifer is presented in this work. A two dimensional finite aquifer is considered, with nr reservoirs located across the aquifer domain. Water injection is allowed through nw arbitrarily located injection wells. The solution to this problem provides the pressure distribution in the aquifer and the average pressure and water influx for each of the reservoirs, as a function of time. The flow behavior in a given aquifer-reservoirs system was found to be governed by the hydraulic diffusivity of the aquifer, the pore volume-total compressibility of the aquifer, (vpCt)a, and of the reservoirs, (vpCt)r, r = 1,2,…, nr the aquifer dimensions, xe, ye, and the location of the reservoirs within the aquifer. These parameters can be estimated through the model by history matching the average pressure of the reservoirs; the estimation of the water influx in each reservoir is obtained through the matching process. A field application of the model is presented, which consists of the characterization of a system of three naturally fractured reservoirs sharing a common aquifer in the Gulf of Mexico. Parameters estimated through the model were found most valuable as input data for numerical reservoir simulation of the system. Introduction Due to the constantly increasing difficulty to discover new fields, it is necessary to dedicate every possible effort to optimize the exploitation of each reservoir. An important field condition that has been reported in the literature is that of several oil fields sharing a common aquifer. For these physical conditions, the reservoirs are in hydrodynamic communication and production from each oil field results in an interference, or pressure drop, with respect to the other neighbor reservoirs. This effect should be properly taken into account in all reservoir engineering studies, otherwise with all adverse consequences, performance predictions will fail to match field behavior. This particular field conditions require a special effort for the characterization of the reservoirs-aquifer system. It is the purpose of this paper to develop a new mathematical model to characterize multiple reservoirs that share a common aquifer, through the analysis of the pressure performance of each reservoir along their productive life. This work also provides a model for studying the production interference of the reservoirs, that result from various production schemes. The Mathematical Model We consider a system of nr oil reservoirs sharing a common aquifer, see Fig. 1. The aquifer is two-dimensional, rectangular, and has uniform thickness and impermeable boundaries. The nr reservoirs are located at any position across the domain of the aquifer, and water injection is allowed through nw wells located across the aquifer. The flow of water in the aquifer is described by the diffusivity equation, with sources and sinks to represent the reservoirs and the injection wells. Reservoirs are handled as block sources of arbitrary shape, defined by the reservoirs-aquifer contact surfaces, while injection wells are considered as line sinks. The behavior of each reservoir is described by means of a conservation equation, stating that the aquifer-reservoir fluid transfer rate minus the total production rate, oil+gas+water, should be equal to the total rate of expansion of the reservoir. Pressure gradients within each reservoir are assumed to be negligible and properties for the aquifer and for each reservoir may, in general, be different. The procedure used to solve the problem posed in the above paragraph consisted of formulating separate mathematical problems, one for the aquifer and nr for the reservoirs.
- North America > Mexico (1.00)
- North America > United States (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)