Summary Steady-state three-phase gas/oil/brine relative permeabilities were measured in a carbonate core under CO2 flooding permeabilities were measured in a carbonate core under CO2 flooding conditions. Results show that the relative permeability of each phase depends only on the saturation of that phase instead of on phase depends only on the saturation of that phase instead of on two saturations, as many previous studies have concluded. All previously reported gas/oil/brine relative permeability studies previously reported gas/oil/brinerelative permeability studies have been conducted with low-pressure N2 gas or air. In this work, CO2 gas, oil, and brine were injected into a carbonate core at 71 degrees C and 9.65 MPa so that the phase behavior and flow would be similar to reservoir conditions. Results show that significant differences exist between the three-phase gas/oil/brine relative permeabilities measured when the gas is CO2 and those measured permeabilities measured when the gas is CO2 and those measured when the gas was N2. Introduction Three-phase relative permeability relations are needed for the design of CO2field projects; for accurate prediction, through numerical reservoir simulation, of CO2 flood performance; and for modeling of production and injection problems. The literature contains empirical, mechanistic, and pore-level models used to predict the relative permeability relationships when two phases are predict the relative permeability relationships when two phases are flowing simultaneously in a porous, permeable medium. Because of the limited amount of consistent experimental data available to determine the model parameters accurately, only the simpler models are usually considered. The typical description given when one extends one of these models to three-phase gas/oil/brine flow assumes that one liquid phase strongly wets the rock matrix, the gas phase is "totally nonwetting," and the second liquid phase is of "intermediate wettability." In these cases, one also assumes that the relative permeability of the wetting and totally nonwetting phases depends only on their respective saturations. One then applies the respective two-phaserelative permeability relation as the three-phase relation for these two phases and need only derive an expression for the relative permeability of the intermediate-wetting phase (kro for a strongly water-wet medium in three-phasegas/oil/brine phase (kro for a strongly water-wet medium in three-phasegas/oil/brine flow). The models for kro most frequently applied include the Corey et al., Naar and Wygal, Land, and Stone models. More recent models or significant model modifications include work by Parmeswar and Maerefat, Fayers, Parker et al., Aleman and Slattery, Baker, and Delshad and Pope. Manjnath and Honarpour and Parmeswar and Maerefat reviewed the models, and Baker and Delshadand Pope recently provided detailed comparisons. Experimental studies of three-phase relative permeability (water/oil/gas) were reported as early as1941 and have continued to trickle into the literature. Oak et al. and Maloney et al. reviewed these experimental studies in detail. Oak et al, presented a very well-documented experimental study resulting from presented a very well-documented experimental study resulting from painstaking attention to procedural detail; their results, along painstaking attention to procedural detail; their results, along with those of Schneider and Owens, are analyzed in more detail below. Maloney et al. (with preliminary work reported by Parmeswar et al.) presented what they described as viscosity Parmeswar et al.) presented what they described as viscosity effects on three-phase relative permeability but, while acknowledging the obvious importance of saturation history, made no mention of it with regard to their own experiments. Maini et al. 18 reported three-phase relative permeabilities measured at 100 degrees C and 3.45 MPa forN2/mineral oil/distilled water in Ottawa sandpacks. Although a modest number of studies have been done in which three-phase relative permeability data have been reported, there is no universally accepted conclusion as to the shape of the isoperms when the data are plotted on a saturation ternary; in fact, oil and gas isoperms are reported as concave, linear, and convex toward the respective apex on the saturation ternary, and brine isoperms are given as concave and linear. In addition, a significant number of the experiments were performed under unsteady-state flow conditions. The interested researcher should evaluate these results with regard to saturation hysteresis, viscous instability, and experimental methods used. What separates our three-phaserelative permeability study from previous studies is our use of CO2 gas instead of air or N2, resulting in phase properties consistent with those observed in afield CO2 flood. The experiments were performed under steady-state conditions, minimizing instability phenomena and allowing for control of saturation history. Saturations were determined by tracer injection. Experimental A single 5 × 45-cm dolomite core was used for these experiments. The core was cut from a block of outcrop dolomite quarried from the Guelph formation in Sandusky County, OH. Commonly called Baker dolomite, the Guelph is a primary, sedimentary grainstone dolomite with intergranular porosity described in some detail by Meister. Its granular matrix gives it a somewhat homogeneous appearance, although there are zones of varying permeability throughout the core, which are evident by detailed visual inspection as well as by X-ray computed-tomography scanner analysis. Permeability measurements of 2.54-cm core plugs showed that permeability varied by as much as a factor of two along the core length. The core PV was found to be 168.4 cm3 at 10.3-MPa overburden,3.45-MPa core pressure (24 degrees C), yielding a porosity of 0.202. The overall brine permeability measured over the total core length (Sw = 1) was 24md. Three fluids were pumped through the core: 0.020-kg/kg CaCl2 brine, n-decane, and CO2. Phase properties were estimated with phase-behavior data according to Dria's methods. From these, the phase-behavior data according toDria's methods. From these, the viscosities, flow rates, and fractional flows were calculated at the mean core pressure. The equipment used in this experimental investigations was arranged to achieve steady-state, nonrecirculating three-phase water/oil/gas flow through the core at a temperature of 71 degrees C and average core pressures of about 9.65 MPa. The once-through flow design was necessary for continuous collection and analysis of effluent needed for determination of tracer response. Flows through the core were controlled through constant injection rate coupled with downstream pressure control. Saturations in this study were attained through steady-state injection of brine, decane, and CO2 into the core until constant pressure drops over each core section (measured through four pressure drops over each core section (measured through four internal pressure ports), constant pressure drop measured between the inlet and outlet core faces, and constant effluent flow rates were observed. Steady-state overall pressure drops for the various experiments ranged from 35 to 480 kPa, with most between 205 and 345 kPa. The three-phase flow rates were designed to maintain total fluxes, u=q/A, of about0.12 m/d. SPERE P. 143

Summary During the last several years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance. While most effort in this field appears to be concentrated on the development of fiber-optic-based meters for temperature, pressure, and flow, comparably few publications have been made to date about the use of fiber-optic technology for monitoring deformations of well tubulars and casings. In this article, we report on recent advances in our development of a real-time fiber-optic-based casing imager. This device is designed for continuous, high-resolution monitoring of the shape of casings or well tubulars and, therefore, enables the determination of strain imposed on the well. Small-scale and full-casing-sized laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10°/100 ft and covers compressive and tensile axial-strain ranges from less than 0.1 to 10%. We will discuss the background technology, measurement sensitivity and strain-response characterization, as well as the scaleup work that has been performed to date. Our article also includes an overview of field-test results and illustrates how real-time deformation monitoring could form a significant component of reservoir-surveillance strategies.

Casing deformation can be used as a direct indicator or measurement of reservoir geomechanical strain, such as may occur withVertical compaction accompanying pressure depletion of high-compressibility hydrocarbon reservoirs;Vertical strain dilation due to stress arching;Shear events associated with fault movement and reservoir bed boundary movement during subsidence;Localized strain events such as pipe ovalization due to highly anisotropic loading or formation strain anisotropy; andPressure changes due to depletion of or injection into reservoirs. Identifying and quantifying these events early can help an operator remedy a potentially damaging production scenario, apply the correct seismic transit time correction during time-lapse reservoir seismic monitoring, or monitor production, injection, and pass-through zones for pressure depletion effects. We have installed, in an industry first, a high-resolution fiber-optic strain imaging system in a producing well. The theoretical, experimental and early deployment test trial details of this technology were reported in SPE 109941, presented at the 2007 SPE ATCE. In this paper, we will report high-resolution strain monitoring results obtained on a set of casing joints which were instrumented with several thousand fiber-optic strain sensors, deployed as a single fiber cable in an onshore production well, installed using normal rig equipment. Of particular interest at this early stage in the well's life is the demonstration of the strain measurement resolution and sensitivity, as evidenced by our ability to monitor the differential pressure between the inside and outside of the casing while circulating prior to cementing, during the cementing operation and while the cement was curing. This monitoring yielded excellent results while cementing the instrumented intermediate casing string, as well as while cementing the production casing string. Cemented at a measured depth of 8000 feet in an unconventional gas well, the strain-instrumented casing joints in conjunction with a distributed temperature sensor and external pressure gauge have continued to provide strain, temperature and behind-casing pressure readings through the remainder of the well construction, completion, hydraulic fracturing and the current, early production operations some six months after initial installation. Introduction The subsurface is host to a number of substantial geomechanical stresses that threaten well integrity. In several instances, this has lead to a complete loss of the well (Cernocky 1995; Morris 1998). For example, reservoir compaction can exert large stresses on a well, which can be initiated by producing from highly compressible layers in the reservoir. As the reservoir fluids are produced, load stresses from the overburden will cause the sediments to consolidate and ultimately compact. Compaction results in both a compression of the reservoir and an extension in the overburden (Morris 1995; Bruno 2002; Bruno 1992). The wells in these zones will undergo significant axial strains and tend to bend and buckle. In addition to compaction, active faults or slip surfaces can also cause intersecting wells to shear and stop producing. Such events threaten not only the life and production of the well, but also the ultimate recovery of a reservoir if they are not effectively addressed as part of a reservoir surveillance program.

In October of 2000, a downhole fiber optic flowmeter was installed in Shell's Mars A-18 well in deepwater Gulf of Mexico. The production tubing-deployed system was installed to a measured depth of 21,138 feet in a highly deviated section of the well, immediately above the producing zones, in 2940 feet of water. This installation represents the first all-fiber optic, multiphase flowmeter system deployed in a commercial well. The fiber optic flowmeter delivers real-time measurements of downhole pressure, temperature, flow rate, and phase fraction. It is completely non-intrusive and contains no downhole electronics or moving parts. The meter requires only one wellhead penetration and is deployed on a single fiber optic cable with the production tubing string during well completion, in a manner similar to conventional, electronic downhole monitoring systems. Installation of the flowmeter at Mars was achieved as planned with no additional rig time required. In fact, the entire well completion operation was finished ahead of the budgeted schedule. This in large part is attributable to pre-job planning and preparations for the entire operation. Performance of the flowmeter at Mars exceeded expectations and demonstrates the value of real-time downhole production data. Along with providing the production engineer with downhole pressure and flow rate data to control draw down while the well was being ramped up, data from the flowmeter provided other valuable information such as a temperature and pressure profile of the well during run-in-hole, well behavior during cleanup, and well productivity data. Mars Field Overview The Mars field was discovered by Shell in 1989 on Mississippi Canyon Blocks 763 and 807 in the Gulf of Mexico, about 130 southeast of New Orleans, Fig. 1. The Mars tension leg platform (TLP) was installed in May, 1996 in 2940 feet of water, Fig. 2. There are 24 well slots, and additionally, a subsea well is tied back to the TLP. Shell Deepwater Production, Inc. is operator of the field and has a 71.5% interest, and BP has the remaining 28.5% interest. The production facilities on the TLP are designed to recover about 500 million barrels of oil equivalent. First production from the TLP was in July, 1996. Current design capacity is 220,000 barrels of oil per day and 220 million cubic feet of gas per day. The oil is transported 116 miles via an 18/24-inch pipeline to shore and the gas is transported 55 miles via a 14-inch pipeline to West Delta 143. Fiber Optic Flowmeter Description The design, development and testing of the downhole fiber optic multiphase flowmeter are described in detail in the companion to this paper and elsewhere.1,2,3 The meter contains no in-well electronics, is non-intrusive, and is capable of robust, reliable operation in harsh downhole environments. It utilizes well established methods to measure the speed of sound of the bulk fluid and the bulk fluid velocity. The speed of sound measurement is combined with a knowledge of the densities and speeds of sound of the individual phases to determine phase fraction (water cut or gas fraction), which is used together with the velocity measurement to determine individual phase flow rates. The novel manner in which these methods are implemented enable full-bore, non-intrusive measurement of pressure, temperature and flow with no downhole electronics. The flowmeter installed in the Mars A-18 well is constructed of Inconel 718. It is compatible with 3 1/2-inch production tubing, with an internal bore of 2.992 inches. The maximum outside diameter of the sensing tube is 5.6 inches. The meter consists of two sub-sections, a pressure section and a flow fraction section, as shown in Fig. 3. The pressure section is about 5 feet in length and contains a 150°C, 15,000 psia fiber optic pressure and temperature transducer. The flow section is about 12 feet in length and contains the fiber optic velocity and speed of sound sensors. Maximum operating conditions of the meter are 125 C and 15,000 psia.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a model that quantifies the production impairment caused by fines mobilization and induced by the transient gradient of pressure from the bean-up operations. Laboratory flow tests using field core samples and synthetic cores composed of different mixtures of sand and fines materials, all stressed under representative in-situ stress conditions were performed. They systematically assessed mechanisms of fines mobilization and amounts of permeability impairment as functions of different sizes of fines, amounts of fines, and flow velocities. Results of flow tests and transient gradient pressures generated by bean-up operations were combined to determine the additional production impairment or skin induced by flow velocity for the well. Application of this model allows engineers to calculate the well skin as a function of drawdown, total time of bean-up, time between choke changes, and number of steps or choke changes in the bean-up operations.Application of this method provided some general qualitative bean-up recommendations (based on production impairment caused by fines mobilization):• Bean-up with smaller incremental drawdown and shorter time between choke changes is preferred to bean-up with a higher drawdown but with a longer waiting time between choke changes • Continuous bean-up is better than step-wise bean-up • Skin inflicted by bean-up is more sensitive to a higher drawdown than to a shorter total bean-up time. • Bean-ups with the same drawdown can be performed faster for reservoirs with higher diffusivity constant The applied field example of a cased hole gravel pack well showed the bean-up inflicted skin ranged between 1 and 3 units. The effect of eliminating the transient gradient of pressure entirely only resulted in a reduction of 1 skin unit. Therefore, at least for this case, the impact of bean-up on production impairment based on fines mobilization was low.Other factors such as flow assurance; rock failures and sand production (and their impacts on sand control completion impairment and reliability) in the near well bore area may be more critical for optimizing the bean-up operations. Further studies in these areas are encouraged. Consideration of fines impairment for bean-up of sand control well is still warranted for formation sand with large amounts of "bad" fines and under low in-situ effective stress conditions. This paper should be of interest to both the completion and production engineering communities.