C.S. Kabir

A simplified model for oil-water flow in vertical and deviated wellbores

This paper presents the results of an experimental study and a semitheoretical analysis of two-phase oil-water flow in vertical and deviated systems. The study focuses on water- dominated flow regimes, where the patterns may be termed as bubbly flow, pseudoslug flow, and churn flow. A drift-flux approach is taken to analyze the flow behavior of oil-water systems. For the three flow regimes investigated, the drift flux of the lighter oil phase is found to be dependent on its in-situ volume-fraction in addition to the terminal bubble-rise velocity. This behavior is in contrast to the gas-liquid flow, where the drift flux has often been found to equal to the bubble-rise velocity. For flow in both vertical and deviated pipes, we were able to develop a single expression for the drift flux, u ow , resulting in a single equation for the in-situ oil fraction, f o , for the three flow regimes studied. We correlated f o with the oil superficial velocity, v os , and the terminal rise velocity, v∞ θ using the expression, f o = v os /{1.2v m + v∞ θ (1-f o ) 2 }. In a deviated pipe, the terminal rise velocity, v∞ θ , is correlated with that in a vertical pipe by v∞ θ = v∞ (cos θ) 0.5 (1+ sin θ) 2 . The performance of the proposed method in estimating f o is in good agreement with our measurements. Published data further augment the approach presented here.

Characterizing the Greater Burgan Field: Use of Geochemistry and Oil Fingerprinting

This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are: I) evaluation of vertical and lateral hydrocarbon continuity 2) identification of production problems due to leaky tubing strings or leaks behind casing and 3) allocation of production to individual zones in commingled wells. The latter two applications are especially important in many older fields, such as Burgan, where tubing and casing string leaks are a problem. For example, Burgan wells which produce Wara oil up the casing and Third Burgan oil up the tubing need to be monitored for the occurrence of mechanical problems. In this case. the chromatography method adds value by reducing the number of high-cost production logging runs and eliminating the associated lost production. Results from this study showed that oils from the major reservoir units are different from each other, even though the differences are small. Furthermore, a number of wells were identified where mixed oils were being produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data showed that Third Burgan oils were different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supported the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study, both in terms of size and scope.

Simplified Wellbore Flow Modeling in Gas-Condensate Systems

Predicting long-term reservoir performance with realistic wellbore models is fraught with uncertainty because of the complexity of two-phase flow. Even a calibrated two-phase-flow model departs from its expected performance trend when changes in flow conditions occur. The full-length paper explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. Statistical results from BHP computations on three independent data sets comprising 167 gas/condensate-well tests show that the homogeneous model compares quite favorably with mechanistic two-phase-flow models.

Characterizing the Greater Burgan Field Using Geochemical and Other Field Data

This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Cretaceous Third Burgan, Fourth Burgan, Mauddud, and Wara. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity and sulfur measurements. From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft long hydrocarbon column which extends across the Burgan reservoirs. Oil compositions vary with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10 °API near the oil-water contact to about 39 °API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense. The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is therefore related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults, which act as seals on a geologic time frame. Compositional differences between groups of oils arise from the reservoir filling process. A third set of parameters correlate with water washing and/or biodegradation processes, indicating oil alteration during production. We are investigating these parameters to determine if they can identify production-time-frame barriers. The geochemical data were integrated with PVT-data for better understanding of the fluid distribution.

Performance of a two-phase gas/liquid flow model in vertical wells

Abstract This paper presents application of a recently developed method for predicting two-phase gas/oil pressure-drop in vertical oil wells. The new method, which is flow-pattern based, is capable of handling flow in both circular and annular channels. Five principal flow regimes-bubbly, dispersed bubbly, slug, churn and annular - are recognized while developing appropriate correlations for predicting void fraction and pressure-drop in each flow regime. Standard oilfield correlations are used for estimating PVT properties of oil and gas: Standings correlation for solution gas-oil ratio; Katzs correlation for oil formation volume factor; Standings, and Chew and Connallys correlations for dead and live oil viscosities, respectively; and Lee et al.s correlation for gas viscosity. A finite-difference algorithm is developed to compute pressure gradient in a wellbore. Computations performed on 115 field tests, involving all the two-phase flow regimes, suggest that the new method performs better than the Aziz et al. correlation. Further comparison of the new methods performance with other standard methods, such as, Orkiszewski, Duns and Ros, Beggs and Brill, Hagedorn and Brown, and Chierici et al., reveals its consistency and improved performance. The test data bank used in this study is that previously used by other authors; thus, validation of the new method is demonstrated with an independent data set.

Establishing Geothermal Gradient Using a New Static Temperature Analysis Method

This work presents a new methodology for determining the static formation temperature (T ei ) by using transient well-test data. We show how a semianalytic method, involving the rectangular hyperbola technique for obtaining T ei , was used for establishing a regions geothermal gradient. Insights into heat-transfer processes were applied to develop methods of data collection and analysis. Several options were enacted to gather valid transient temperature data. For instance, sensor placement above the test interval ensured that the produced fluid had the opportunity to cool during shut-in periods, thereby creating useful perturbations. Tests accompanied by large pressure drawdowns caused Joule-Thompson heating, leading to subsequent cooling during well shut-in, even when the sensor was at the midpoint of a producing interval. Transient temperature data were gathered during pressure buildup tests in various boreholes ranging from 2,200 to 14,500 ft, encompassing different geologic horizons in Kuwait. Data collected from traditional open- and cased-hole logging were used and compared with the new approach. Statistical analyses clearly showed the superiority of the proposed procedure. Results of the new approach established Kuwaits geothermal gradient (g G ) at 0.012 °F per ft with a mean surface temperature (MST) of 87.23 °F.

Characterizing the Greater Burgan field : Integration of well-test, geologic, and other data

Pressure transient testing happens to be a powerful reservoir characterization tool when used with geological, geophysical, petrophysical, cased-hole logs, and completion data. This work describes a multidisciplinary approach to understanding reservoir flow units in the Greater Burgan field in Kuwait. Major reservoirs in this field were deposited in a fluvial deltaic environment. As expected with this geologic setting, we encounter a wide variety of reservoir stratigraphy. These include complex discontinuous sands associated with a delta plain environment, massive distributory mouth bar/delta front sands, and open marine carbonates. Transient tests, aided by reservoir geology, helped determine depositional environments, fluid contacts, the sealing nature of faults, etc. Distributed pressure measurements contributed to our understanding of vertical flow barriers, while geochemical analyses augmented our understanding of reservoir units, both in vertical and lateral sense. We interpreted over 400 well-tests, spanning four decades, to characterize the major layers, which are being produced separately in this giant field. We observed a variety of examples that identify channel-levee systems, gas-cap or aquifer support, layered reservoir behavior, partial-completion and dual-permeability effects, and non-sealing faults. In short, many recognizable well-test signatures were discerned, leading to much improved understanding of various flow units. Average drainage-area pressures were estimated using the rectangular hyperbola method. Application of this robust technique became very useful because different geologic horizons and/or reservoir areas experience various degrees of pressure support.

Analytic Wellbore Temperature Model for Transient Gas-Well Testing

Questions arise whether bottomhole pressures (BHP), derived from their wellhead counterpart (WHP), lend themselves for transient analysis. That is because considerable heat exchange may affect the wellbore density profile, thereby making the WHP translation a non-trivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations. This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHP’s on a spreadsheet. Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface and partial wellhead information was available in the other. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable. Introduction Gas well testing is sometimes conducted by measuring pressures at the wellhead. Both cost and circumstance (high pressure, high temperature or HPHT) often necessitate wellhead pressure (WHP) monitoring or run the risk of having no tests at all. Methods for computing BHP from wellhead pressures for steady flow in gas wells are well established in the literature. For dry gas wells, the widely used method of Cullender and Smith is most accurate, as testified by subsequent studies. For wet gas, either a two-phase model, such as the one offered by Govier and Fogarasi, or the modified Cullender-Smith approach appears satisfactory. However, these methods apply to steady-state gas flow and implicitly presuppose that the wellbore is in thermal equilibrium with the formation. These assumptions may be tested during a transient test. That is because unsteady-state wellbore heat transfer occurs even after the cessation of the wellbore fluid storage period. Steady-state fluid flow ordinarily implies absence of wellbore effects from the viewpoint of transient testing. Consequently, one needs to develop working equations by conserving mass, momentum, and energy in the wellbore to capture physical phenomena. Earlier, we presented a forward model and showed its capability to reproduce BHP, WHP, and WHT, given reservoir and wellbore parameters. However, translation of WHP to BHP was not demonstrated clearly. The intent of this work is to present a framework for rigorous computation of BHP from WHP. To achieve this objective, we developed analytic expressions for depthand time-dependent fluid temperature during both flow and shut-in tests. These temperature relations, in turn, allow computation of gas density and, therefore, pressure at any point in the wellbore. Methodology The following expressions for the wellbore-fluid temperature, Tf, are developed in Appendix A by conserving energy while conserving momentum iteratively. For mass conservation, steady-state assumption is used. The Tf expressions are ( ) ( ) , 1 1 sin ) ( ψ θ R L L z

An Analytic Simulator for Rapid Forecasting Rate Behavior of Oil Wells

A generalized analytic approach is used for forecasting an oil wells rate behavior. Well orientation from vertical to horizontal can be adapted in this formulation. In this approach, the well is produced at a constant bottomhole pressure. in which flow periods of infinite-acting, transitional, and pseudosteady-state (pss) are modeled. The method of images is used to compute pressure solution during the transitional and pss flows for bounded reservoirs. Thereafter, rates are discerned. Both no-flow and a combination of no-flow and constant-pressure boundaries may be used. We developed a sensitivity analysis procedure to account for uncertainty in reservoir parameters. Here, a number of parameters, such as drainage area permeability, decline coefficient can be varied within specified bounds to generate a cumulative probability distribution function (cdf). The individual simulations that fall closest to 10, 50, and 90 percent of this cdf are selected to represent low, medium, and high forecasts for oil rates. This analysis readily allows one to perform an economic evaluation of existing or new well prospects. Direct comparison of a vertical well with that of an inclined or a horizontal wells performance is also feasible in this approach. Illustrative examples constitute the papers backbone. Several plausible scenarios are presented to show the simulators applications. The first three cases, taken from actual files, show how project economics can be analyzed from the results of a large number of rapid simulations. We also considered a hypothetical case involving an offshore project where a large capital investment is required. Following a stepwise procedure. we show how to evaluate the reservoir parameters that are required to make the project an economic success even before drilling a well.

Performance Evaluation of Horizontal Wells in a Tight Carbonate Reservoir

This paper presents a case study of evaluation of the performance of horizontal wells drilled in a tight carbonate reservoir in Kuwait Successful wells were those that intercepted natural fractures. A methodology was developed to define the reasons for the performance of horizontal wells. The methodology involved use of geological, petrophysical, geochemical, transient test, rock, and fluid properties to develop a numeric simulation model. Conclusions regarding well performance were made by using a newly developed analytic simulator and the numeric model. While the analytic simulator provided rapid rate forecasts, the numeric simulator gave insights into the causes for unsatisfactory well performance. For example, well placements within the bed, low-permeability rock, and unfavorable relative permeability characteristics all contribute to the rapid rate decline and the associated increasing gas/oil ratio (GOR) production. We proposed cyclical production and oil injection-production schemes to address the high-GOR production problems. In the first scheme, a well is produced and shut-in in an alternating fashion to preserve the reservoir energy, Oil is injected for a very short duration to alleviate the near-wellbore gas saturation problem in the second scheme. In both cases, the high-GOR production is minimized and the ultimate oil recovery is improved.