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.
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.
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.
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.
During drilling operations, downhole conditions may deteriorate and lead to unexpected situations that can result in significant delays. In most cases, warning signs of the deterioration can be observed in advance, and by taking proactive actions, drillers can avoid serious incidents such as packoffs or stuck pipes. A new analysis methodology, relying on an automatic real-time computer system, has been developed to detect those early indicator conditions. The methodology involves constantly computing the various physical forces acting inside the well (mechanical, hydraulic, and thermodynamic). These physical forces are coupled by an automatic model calibration, which then gives a reliable picture of the expected well behavior. Through analysis of the deviations between modeled and measured values, an estimation of the current state of the well is derived in real time. Changes in the well condition are an early warning of deteriorating well conditions. This paper precisely describes the real-time analysis and the results during some drilling operations. The software has been used for monitoring 15 unique wells located in five different North Sea fields. All major situations were signaled in advance at different event time scales: Rapidly changing downhole conditions (such as pulling a drillstring into a cuttings bed) were typically detected 30 minutes ahead of the actual event, medium-duration deteriorations were detected up to 6 hours before the incident, and slow-changing downhole conditions were signaled up to 1 day in advance. Several examples that illustrate the detected incidents over distinct time periods are described. The availability of good-quality real-time data streams makes it possible to implement such analysis tools in an integrated operation setup. Early symptom detection can be used to make decisions in a timely fashion, on the basis of quantitative performance indicators rather than subjective feelings and personal experience.
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.
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.
Downhole pressure and temperature sensors have been installed either separately as stand-alone sensors hanged on the production tubing of a well or jointly with Electric Submersible Pumps (ESPs) or Intelligent Well Completions (IWC). However, their utilization thus far has been limited to static/flowing bottom-hole pressures measurement for buildup/drawdown pressure tests analysis or ESP/intelligent well performance monitoring.
Eighty-eight (88) wells located offshore Saudi Arabia have been equipped with ESPs combined with downhole pressure and temperature sensors installed at the intake and discharge of the pumps. Each well was equipped with a surface coriolis meter to measure the total liquid flow rate and water-cut assuming that the well's production will be maintained above the bubble point pressure. However, the coriolis meters' readings have become erroneous ever since the wells' flowing wellhead pressure declined to and below the saturation pressure due to the flow of liberated gas through the meters. In order to compensate for the meters' measurement deviation, wellhead samples had to be collected and analyzed to determine the wells water-cuts where the total flow measurement was still acceptable. Alternatively, other means of multiphase flow rate measurements were used. This has proven to be costly and time consuming.
This paper proposes a technique which uses real-time data transmitted from existing surface and subsurface sensors to calculate the water-cut and flow rate of each well and avoid the risky and costly field trips for wellhead sample collection and analysis. In addition, the paper describes an innovative technique to estimate the error in the measured density and calculated water-cut based on the bubble point pressure which accurately determines the application envelope of this method. The paper provides examples to illustrate the validity of the proposed technique in comparison with measured and sampled water-cuts which were collected above and below the bubble point pressure. Furthermore, the paper sheds light on the main issues impacting the method's reliability.