The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations.
A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests.
This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
Development of offshore hydrocarbon (HC) fields is today's oil and gasindustry priority in the Russian Federation. Water areas of the Arctic shelfare considered to be potential offshore HC production regions. When designingpipelines for such fields it is necessary to take into account the impact ofspecific Arctic conditions including hazardous ice impact (ice gouging),possible presence of permafrost on the seabed, lithological andgeomorphological distinctive features of bottom soils. All main parametersensuring safety of offshore pipelines must be determined and validated at theearly design stage.
The paper reviews one of the main conditions that influences reliable operationof underwater pipeline systems, namely, stable position of the underwaterpipeline at design reference marks.
Calculations of offshore pipeline stability on the seabed use the followingmain conditions:
- environmental conditions;
- geotechnical conditions of the seabed;
- bathymetrical conditions (water depth);
- pipeline parameters (diameter, wall thickness).
Criteria of pipeline stability on the seabed include:
Soils with weak strength properties, especially when they are used forbackfilling, may be potentially dangerous due to liquefaction underhydrodynamic forces. It is especially dangerous in the first years of operationwhen the soil is not consolidated enough. Relief in a local zone of dilutedsoil causes longitudinal stresses in pipeline, which may result in offshorepipeline stability loss. Liquefied soil potential depends also on backfillingprocess technology. This operation is performed by special ships - dredgers.Such ship has two pipes, one for soil suction, and the other equipped withwater injection nozzles - for washing out and backfilling. When a trench isbackfilled with controlled soil flow, "front" of backfill material is formedunder pipe working head and a layer of fluidized material appears in the upperpart of this "front". Therefore, if weak soil is used as backfill material, asize of liquefied soil layer will be considerable, as well as its impact on thepipeline. This process may lead either to floating up or submerging of pipelineinto the soil. To stabilize offshore pipelines position the following measurescan be taken: backfilling with soil not subject to liquefaction; pipelinelaying below the layer of liquefied soil to eliminate risks related to soilliquefaction; using different methods of ballasting.
The number of azimuth thrusters configured for ice conditions is constantlyincreasing. This is due to the common tendency of widening the range ofoperation of a particular ship in terms of weather conditions, operating modesand geographical areas to achieve more business opportunities throughout theoperating life of the ship. The other major factor is the large potential foroil and gas in the arctic waters. It is also estimated that the number oficebreakers using azimuth propulsion will increase in the near future as theexisting fleet will be modernized and new vessels are built.
The new PC rules have recently been introduced and that has changed theclassification process significantly. Although being clearly more accurate, thenew rules require much more calculation work and have several parametersrelated to the thruster itself.
A first Azimuth thruster has now been classified according to the new PCrules. The thruster, type UUC 505, was originally classified according to DetNorske Veritas Ice-10 ice class which represents an ice class (at the lighterend) for arctic conditions. The thruster was then subsequently classifiedaccording to Det Norske Veritas PC4 ice rules.
The purpose of this presentation is to highlight the practical issues andthe increased workload that the new PC rules have brought on to theclassification process. Also it will highlight some points in the rules whereclarification is needed.
Reel-laying is a fast and cost-effective method to install offshore pipelines. During reel-laying, repeated plastic strain is introduced into the pipeline which may, in combination with ageing, affect strength and ductility of the pipe material. The effect of reel-laying on the pipe material is achieved by small- or full-scale reeling simulations followed by mechanical testing according to corresponding standards. In this report an appropriate test setup for full-scale reeling simulation is presented. The fitness-for-use of the test rig is demonstrated by finite element calculations as well as by full-scale reeling simulations on different pipes of various grades. Plus, small-scale reeling simulations with subsequent ageing and mechanical testing are performed on the same pipe material. A comparison of results from mechanical tests after small- and full-scale reeling simulations is given. Additionally results from collapse tests on pipes after full-scale reeling simulations are presented, and the influence of repeated bending of the pipe on its collapse behavior is discussed.
Two main concepts are normally used for laying offshore subsea pipelines. In the S- and J-lay method a pipeline is fabricated on the deck of a lay barge by welding individual lengths of pipe as the pipe is paid out from the barge. The pay-out operation must be interrupted periodically to permit new lengths of pipe to be welded to the string. The S- and J-lay method requires skilled welders and their relatively bulky equipment to accompany the pipe-laying barge crew during the entire laying operation; welding must be carried out on board and often under adverse weather conditions. Further, the S- and J-lay method is relatively slow, with even experienced crews laying only few miles of pipe a day. This can subject the entire operation to weather which can cause substantial delays and make working conditions quite harsh.
For burst design, engineers routinely assume that the casing annular space is filled by a fluid equivalent. This assumption ignores mechanical resistance provided by solid cement. Some studies addressed this shortcoming by modeling the cement sheath as a solid with elastic failure criteria. Prior work used cement elastic modulus and Poisson's ratio to classify cement as "ductile" (soft) or "brittle" (hard). In the current study, numerical results from finite-element analysis (FEA) indicate that casing burst resistance is increased by the presence of the cement sheath. This study focuses solely on improvement offered by the cement sheath to casing burst resistance and ignores consequences of cement failure on overallwell integrity. Comparisons are provided for casing burst resistance, assuming various backup profiles. These include fluid hydrostatics, solid cement matrix (both elastic and plastic response), and cement as "loose" particles. The fluid hydrostatics include mud weight in hole, cement-slurry density, mixed-water density; normal pressure (saltwater column), and actual pore pressure. Calculations show that these fluid profiles are conservative when used as burst-resistance backup. Original cement-slurry density is least conservative. Because well designers are familiar with fluid profile backup assumptions in casing burst design, recommendations are provided to approximate cement behavior as particles with a fluid profile. This allows ease of calculation and is consistent with current practice. Guidelines are provided to explicitly calculate the enhanced casing burst resistance caused by the particulate cement.
Oil wells typically have multiple concentric casing strings. For a set of two concentric strings, if the inner pipe has a compressive axial force, it will typically buckle within the outer string. The buckling of pipe can be important in the analysis of a well-completion design because the buckled pipe can develop bending stresses that may be significant. Most analyses of this problem assume that the outer casing is rigid. In reality, this external casing is also elastic and would displace owing to the loads generated by contact with the inner pipe. Further, if both strings have compressive axial forces, both strings will buckle, and the resulting buckled configuration must fit together so that contact forces between the two strings are positive and the pipes do not each occupy the same space. If the two strings have an external, cylindrical rigid wellbore, then any contact forces with this wellbore must also be positive, and the buckled pipe system must lie within this wellbore. The only known solution to the multiple concentric pipe-buckling problem is that of Christman (1976), who proposed a composite pipe based on the summed properties of the individual pipes. This analysis does not conform to the requirements posed in the preceding paragraph. This paper presents the various ways that two concentric pipes can interact when one or both pipes are in compression and would then have a tendency to buckle. The contact forces between the pipes and with the external wellbore are explicitly calculated, and contact or noncontact conditions are determined. All results are analytical so that they can easily be used in spreadsheets or hand calculations. Several examples of calculations are presented to illustrate how these results might be used.
Efficient and robust phase equilibrium computation has become a prerequisite for successful large-scale compositional reservoir simulation. When knowledge of the number of phases is not available, the ideal strategy for phase-split calculation is the use of stability testing. Stability testing not only establishes whether a given state is stable, but also provides good initial guess for phase-split calculation. In this research, we present a general strategy for two- and three-phase split calculations based on reliable stability testing. Our strategy includes the introduction of systematic initialization of stability testing particularly for liquid/liquid and vapor/liquid/liquid equilibria. Powerful features of the strategy are extensively tested by examples including calculation of complicated phase envelopes of hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
Air emissions from combustion sources are monitored by different techniques such as use of emission factors, engineering calculations, periodic stack monitoring, Continuous Emission Monitoring Systems (CEMS) and Predictive Emission Monitoring System (PEMS). CEMS despite being seen as best practice but is expensive and requires extensive maintenance. PEMS has become recently popular in estimating real-time emissions from various air pollution sources using measured process parameters. Abu Dhabi Company for Onshore Oil Operations (ADCO) based on a wide techno-economical survey had chosen PEMS to monitor its emission and maintain compliance report on air quality as per the requirements of Abu Dhabi National Oil Company ADNOC. In addition, ADCO's innovation ensured additional modules to monitor energy performance and also provide a platform for maintaining energy and emission KPIs. ADCO commissioned the first pilot PEMS in Bab field in 2010 covering all emission sources and typical units of the major energy users such as gas turbines, heaters, oil export pumps, water injection pumps and gas compressors.
PEMS real-time information and remote access through web helped in taking prompt corrective actions to control equipments and optimize use of fuel which resulted in subsequent reduction of energy and Green House Gases (GHG) emissions besides compliance assurance against ADNOC's air emission limits for process units. PEMS was proven to be as accurate as the hardware based CEMS over the entire range of operations and therefore it can be readily applied for tracking air emissions and energy efficiency from gas turbines, heaters at marginal cost. In addition to providing data for emissions compliance, ADCO was able to use the PEMS to optimize machinery operation for better performance and efficiency, and consequently reduced emissions.
This paper demonstrates ADCO's success in integrating energy performance and emissions reporting in one simple yet effective solution. The paper further describes how the PEMS was able to integrate data from various plant sources into one reporting system while at the same time meeting ADCO IT protocol.