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Abstract A new method of measuring both the oil and/or water velocities in producing horizontal wells has been developed. This approach uses both water-soluble and oil-soluble chemical markers, each of which is insoluble in the other fluid phase. The markers are injected into the borehole by a logging tool at one location and detected by a pulsed-neutron tool at a second location. The transit time between injection and detection of the marker gives a measurement of the fluid velocity. Since the markers are soluble in only one phase, the velocity of each phase can be measured separately. This measurement has been made under laboratory conditions (flow loop) to measure velocities from 10 to 500 ft/min at horizontal and several degrees deviation from horizontal. The results of these tests show good linearity and repeatability of the measurement. An experimental downhole logging tool has been built in order to perform the oil and water velocity measurements in real wells. This tool has logged several horizontal wells in combination with other production logging tools. Logs from several of these wells will be shown to validate the measurement. Introduction As horizontal wells have become more prevalent, the ability to reliably evaluate the production performance of these wells has become increasingly important. Existing production logging techniques, such as spinners, that have been successfully used in vertical wells cannot always be applied to horizontal wells with full confidence due to the segregated flow in the borehole. For this reason, new techniques must be developed to evaluate oil and water flow rates in horizontal wells. To determine the flow rates of the oil and water phases in a horizontal well, one must either 1) measure the individual oil and water flow rates directly, or 2) measure the individual oil and water velocities in addition to their holdups. (It should be noted, that for most production logging applications in horizontal wells, measuring only the holdup or only the velocity of the production fluids is usually insufficient to determine the source of production problems.) This paper will address part of the second approach, the measurement of individual oil and water velocities. Once determined, these velocities can be combined with holdup information, obtained from several possible approaches to obtain oil and water flow rates. Background Several currently available technologies make it possible to measure water velocity in horizontal wells. The oldest of these uses a radioactive tracer such as Iodine-131 with an 8-day half-life. The iodine is placed in a water-soluble form. This material is injected into the borehole and then measured as it passes a gamma-ray detector. The time between injection and detection enables the calculation of the flow velocity of the water. This method can also be applied with some success to oil velocity measurements by placing the iodine into an oil-soluble form. The limitation of this approach is that the oil-soluble form is usually an emulsion that can exhibit some unique problems due to the nature of emulsions. With the increased restrictions and risks associated with the use of radioactive tracers in the borehole, it is desirable to have a method of performing these velocity measurements without using radioactive tracers. This is one of the reasons that the WFL Water Flow Log was developed. This approach relies on the activation of oxygen in the water using a 14-MeV neutron generator and measures the transit time of the activated oxygen in the borehole, thus giving a measure of the water velocity. This technique has been successfully applied to flow in the borehole and behind casing or tubing. Unfortunately, this method does not address the oil velocity measurement. A new approach has been developed that is capable of independently measuring the oil and water velocities in horizontal wells without the use of radioactive tracers. The PVL Phase Velocity Log uses a chemical marker for its measurement and is therefore a much safer approach to these velocity measurements. P. 943
- North America > United States (0.46)
- Europe > United Kingdom (0.28)
- Europe > Norway (0.28)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract In horizontal wells, it can be very difficult to interpret conventional production logging tools due to the fluid segregation in the borehole. This is a even more of a problem when there are more than two phases present in the borehole, i.e., oil, water, and gas. A pulsed-neutron tool measures many parameters which are differentially sensitive to all three possible borehole phases. Therefore, it is possible to combine the information available from a pulsed-neutron tool to determine the 3-phase holdup in horizontal wells. One of the major difficulties in evaluating the response of a tool to 3-phase holdup is obtaining good data under realistic downhole conditions, i.e., realistic gas densities. Laboratory measurements cannot readily be made under these conditions; therefore, modeling techniques must be used to evaluate and characterize tool response. To validate a computer model, laboratory data are needed for benchmarking; therefore, for this study, over 400 laboratory formation measurements were performed using air to simulate gas. These formation conditions were also modeled using Monte Carlo techniques. The agreement between measured and modeled data proved to be good enough that modeling can be used to confidently predict the tool response with air or realistic gas. Once the ability to predict tool response under realistic downhole conditions exists, it is possible to combine information from a pulsed-neutron tool to quantitatively determine the holdup of all three phases. This is accomplished by combining the inelastic near/far ratio with the near and far carbon/oxygen (C/O) ratio. This approach to the holdup measurement has been demonstrated using a combination of laboratory data, Monte Carlo modeling, and field data. The results of this study have demonstrated that the RMS accuracy of this measurement is about 6% on each of the three phases. Introduction As horizontal wells have become more prevalent, the ability to reliably evaluate the production performance of these wells has become increasingly important. Existing production logging techniques, such as spinners, that have been successfully used in vertical wells cannot always be applied to horizontal wells with full confidence because of segregated flow in the borehole. For this reason, new techniques must be developed to evaluate oil and water flow rates in horizontal wells. To determine the flow rates of the oil and water phases in a horizontal well, one must either 1) measure the individual oil and water flow rates directly, or 2) measure the individual oil and water velocities in addition to their holdups. (It should be noted, that for most production logging applications in horizontal wells, measuring only the holdup or only the velocity of the production fluids is usually insufficient to determine the source of production problems.) This paper will address part of the second approach, the measurement of individual oil, water, and gas holdups. Once determined, these holdups can be combined with velocity information, obtained from several possible approaches to obtain oil and water flow rates. Background Pulsed-neutron tools have previously been used to qualitatively determine the 3-phase holdup in horizontal wells. This approach uses the borehole sigma and the inelastic near/far ratio for this determination. The method is considered qualitative since tool calibration information is not available for the ratio measurement or the sigma of the gas. Recent work reported by Peeters et. al. has attempted to quantify the pulsed-neutron measurement for holdup in horizontal wells. Their approach utilizes three measurements from a single pulsed-neutron tool centered in the borehole: C/O windows ratio, borehole sigma, and capture near/far ratio. The measurements are combined through a linear response matrix to produce the desired holdup measurements. The coefficients for the matrix are determined by regression of modeled or measured tool responses to known conditions. A more quantitative approach has been employed with the RST Reservoir Saturation Tool. P. 895
- Well Drilling > Drilling Operations > Directional drilling (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)
Characterizing Horizontal Well Performance in a Tight Gas Sand Using Pressure Transient, Production Logging and Geological Data
Churcher, P.L. (PanCanadian Petroleum Limited) | Kenny, J. (ATECH Applications Technology Limited) | Lamb, D.H. (ATECH Applications Technology Limited) | Flach, P.D. (Virtual Computing Services Limited)
Abstract Pressure transient analysis is routinely used to determine insitu reservoir parameters and the deliverability of vertical gas wells. It can also be used to determine these same parameters in a horizontal gas well using techniques similar to vertical well test analysis. The interpretation of the data can be substantiated using other sources of information such as production logging, gas production while drilling, and geological and numerical simulation models. Data obtained from an experimental vertical and horizontal underbalanced drilling program conducted in the Westerose Field in 1994 and 1995 is used to demonstrate the power of this reservoir management tool. The results indicate that the vertical permeability is too small to economically produce from unstimulated horizontal wells in the tighter interbar sands, and consequently fracture stimulation will be required. Introduction The Westerose Gas Field is located in central Alberta, Canada, approximately 75 km south of the city of Edmonton (Figure 1). Rich gas, containing up to 300 m3 of liquids per 1 ร 106 m3 of gas (46 bbls per mmscf), is produced from the tight sandstone of the lower Cretaceous Glauconitic Formation at an average depth of 1850 m (6050 feet) and an average reservoir pressure of 15.5 MPa (2550 PSI). The original gas in place for this field is estimated to be 30 ร 109 m3 (1.2 Tcf). The Glauconitic Formation in this area was deposited as part of the Hoadley Barrier Bar-Barrier Island Complex. The sands are typically 20 to 30 m thick (60 to 90 feet) and can be subdivided into an upper, permeable sand (1 to 10 mD in core at benchtop conditions) and a lower tight sand (generally less than 0.5 mD in core at benchtop conditions). The upper and lower sands are separated by an impermeable shaley siltstone, informally referred to as the Middle Glauc Shale (Figure 2). The reservoir quality of the lower sand is relatively uniform throughout the area, but the upper sand is highly variable. In some cases the upper sand forms permeable barrier bars that trend NE-SW. In other cases the upper sands are similar in reservoir quality to the lower sands. These sands are referred to in this paper as interbar sands. There are at least five bar sand trends in the area of the pilot that are separated by tighter interbar sands. Measurements of the regional stress orientation from recent ultrasonic borehole images of an open hole fracture stimulation treatment indicate that the maximum principle stress orientation runs parallel to the main bar trends. An experimental drilling pilot project was conducted in this field in September 1994 to test the feasibility of accessing rich gas reserves in a tight sandstone reservoir using underbalanced drilling technology. The results from a lab study indicated that a carefully designed underbalanced drilling fluid would result in a substantial reduction in the formation damage and would likely dramatically improve the productivity of these damage-prone sands. The first phase of this project involved drilling four vertical wells and setting casing to the top of the sand. The pay zone was then drilled out underbalanced using coiled tubing. The results of this program are documented elsewhere. Both pre and post-frac pressure transient analysis were conducted on two of these wells. Some of these data have been used in this paper to support the interpretations made using the horizontal pressure transient data. The success of the vertical well pilot led to the implementation of a horizontal underbalanced pilot program in December of 1994. The first well drilled in this program, 3-33-44-2WS, targeted both the upper and lower sands. Although no full flow and build-up data was gathered for this well, a partial build-up analysis conducted on the lower sand in the heel of the well during drilling showed that the Middle Glauc Shale likely represents a regional permeability barrier. P. 761
- North America > Canada > Alberta > Wetaskiwin County No. 10 (0.54)
- North America > Canada > Alberta > Ponoka County (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Westerose Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Carla South prospect > I-7 Well (0.99)
- North America > United States > Utah > Island Field (0.98)
Abstract A number of production logs in the Troll Oil production wells have been performed. Horizontal screen sections up to 2000 m required logging tool deployment by coiled tubing. All wells flowed monophase oil. Practical correction procedures for the logs are proposed. The corrections cover annular flow between screen and open hole, coiled tubing displacement flow, coiled tubing influence on drawdown and productivity due to reduced flow area. The correction procedures are essential for interpretation of individual layer productivities, which is demonstrated on field examples. Introduction The Troll Oil field is located in 300 m water depth offshore Norway. The field is characterized by a thin oil zone (13โ26 m) sandwiched between a large gas cap and active aquifers. The reservoir contains several highly permeable unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite layers occur within the high permeable sands. Several publications describing the Troll Oil horizontal well development are available. The production logs performed on the Troll oil wells had two main objectives:verify cleanup of the well after setting of kill pill, determine the productivity and permeability profiles along the well. In long horizontal wells with small drawdowns (a typical value during logging at 2000 Sm3/d of the Troll Oil wells is 0.2 Bar), the production log analysis is not straightforward, and a number of corrections to the measured data must be performed to obtain representative production inflow profile along the completion interval. The most important corrections identified for the Troll Oil wells are (1) coiled tubing displacement flow, (2) coiled tubing influence on drawdown and productivity due to reduced flow area, and (3) annular flow between screen and open hole. In addition water or kill fluid accumulation at low points in the well may corrupt the spinner flowmeter response. This paper discusses possible methods to correct for these effects. A possible disturbance of the velocity profile in the screen due to radial inflow has not been accounted for. Mathematical Modeling Fig. 1 and 2 show the flow in the screen section with and without coiled tubing present. To understand the influence of the coiled tubing mass and momentum balance of a horizontal well section with and without a coiled tubing is required. The analysis is similar to that performed by Dikken, with the addition of the acceleration pressure drop and the coiled tubing effects. Mass Analysis. From Fig. 3 the following mass balance equations are obtained for a control volume with coiled tubing partly inserted (1) or, equivalently, (2) For a control volume without coiled tubing we get (3) P. 699
- Europe > Norway > North Sea > Northern North Sea (0.35)
- North America > United States > Texas (0.28)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (9 more...)
Abstract A new analytical method of gas and water coning evaluation for horizontal (H) and vertical (V) wells is presented. In dual coning there are five kinds of breakthrough (BT). Both gas and water apex have a parallel evolution and this fact is very important for behaviour of recovery factor (RF). Then analytical correlations for RF are presented followed by examples of calculation. RF depends mainly on well position (and its perforation), oil rate, anisotropy and capillarity. Introduction The most remarkable papers on coning phenomenon are Muskat and Wickoff, Sobocinski and Cornelius, Bournazel and Jeanson and Weiping and Wattenbarger. The main sources for analytical solutions are classical books by Carslaw and Jaeger and Muskat and recently books by Chaumet and Streltsova. Pietraru and Cosentino published in 1993 a new fully analytical approach. This method has been generalized and extented for dual coning. Muskat and Wickoff (figs. 4 and 5) was the source for the new concept of "radius coning". The references, were used for analytical solution of diffusion equations, with various boundary conditions. This paper presents briefly the new method, after references, then presents criteria for different kinds of breakthrough and new correlations for recovery factor (actual and maximum) in dual coning. Dual coning Correlations for dual coning parameters Fig. 1 presents a geometrical scheme for dual coning. Main hypothesis is that gas oil contact (GOC) and oil water contact (OWC) are influenced by one well only (no interference). Dupuit's hypothesis is accepted (when the vertical flow composants are neglected). The pressure drop controls both gas and water apex and if gas-cap and aquifere are very strong the pressure drop in gas and water are neglected. Then the heights of apexes are given by the following expressions: (1) (2) where po is the pressure drop in oil between the initial pressure and the pressure at the apex. In this condition both height of gas and water apexes are directly proportional to the po and inversely proportional to density difference. Constant C1 depends of unit system (see Table 1). Coning Radius. Pietraru proposes the new concept of "coning radius" and its empirical expression: (3) The radius coning is a very important parameter. It defines the value of abscissa controlling the critical coning height. Correlation of oil rate versus time of BT Fig. 2 presents the main correlation of dimensionless rate as function of three dimensionless parameters (see Appendix A) (4) General solution. A new solution is given with the hypothesis that the oil rate is the sum of three terms: first term is the rate of an horizontal drain (with length 4, see appendix A) and both second and third terms are equal to half rate of V well. P. 169
- North America (0.28)
- Europe (0.28)