Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract The oil and gas industry has a need for reliable monitoring of changes in wall thickness both topside and subsea. It is important to detect and monitor the effect of corrosion and erosion as this may reduce the life-cycle cost and increase the lifetime of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside the conditions of operation can be extremely hostile, facing problems like surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when you have to take into account factors like high pressure and limited access. Over the last years ClampOn have offered a topside corrosion-erosion monitor (CEM) for monitoring changes in the wall thickness of such infrastructure. Major advantages of this technology have been its non-invasiveness, high repeatability, high coverage and the lack of any transducer movement, also making it an excellent candidate for subsea use. The measurement principle is based on dispersion of ultrasonic guided wave modes, and by using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information – not as a spot measurement, but as a unique average path-wall thickness. With several successful installations topside, the technology has now also been made available for subsea installation.
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (0.67)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.40)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea production equipment (0.34)
Abstract Production logging measures downhole flow properties under dynamic conditions with an objective to gain insight into the downhole flow dynamics and quantify zonal flow contributions. Production logs are acquired during "stabilized flowing and shut-in conditions?? and the observed flow behavior is assumed to be representative of the reservoir flow behavior. In a homogenous reservoir this assumption may not be far from reality. Heterogeneous reservoirs, however, pose another challenge. Flow dynamics observed in heterogeneous reservoirs can be time dependent; therefore the time frame of data acquisition is critical to the conclusions that can be drawn from the interpretation. Presented herein is a case study of production logs acquired in a seemingly homogenous reservoir, the interesting dynamics observed from the data, and the methodology used to unravel the reservoir behavior. The production logs acquired during shut-in conditions revealed downhole cross flow between the reservoir layers. However a change in the direction of cross-flow between two shut-in acquisitions, acquired within 10hours of each other, revealed a much more complex reservoir than originally anticipated. Further analysis of the data and integration with other reservoir evaluation techniques revealed the heterogeneity of the reservoir with the existence of three radial compartments exhibiting different reservoir pressures, mobility and productivity index. The flow behavior observed from the production logs is unique and provides an insight to downhole flow dynamics in heterogeneous reservoirs. The methodology used in unraveling the reservoir behavior, and the integration of the production logs with other reservoir evaluation techniques, aided in improving reservoir characterization and ultimately reservoir management. Introduction Production logs provide measurements of downhole flow properties to promote an understanding of the downhole flow repartition of several zones, which then provides more information on the contribution the different reservoir layers make to the total production. In a homogenous reservoir, with constant properties, the reservoir response does not change with time and the flow behavior recorded at any time can be assumed to be representative of the reservoir behavior. However, in a heterogeneous reservoir, the nature of the reservoir may cause its flow behavior to change with time. A typical example will be a dual porosity reservoir system: in a dual porosity system, the reservoir is described to be composed of two systems - a block system and a matrix system. The matrix system has high permeability but low storativity, meaning that the fluid will flow faster through the matrix but it does not have enough volume to support the production (Fig 1). The block system on the other hand has high storativity but low permeability, meaning that fluid cannot flow directly from the block system into the wellbore. The fluid will flow from the block system into the matrix and then into the wellbore (Fig 2). When this type of reservoir is put on production, the initial flow will be from the matrix and the time it will take for the pressure to equalize between the matrix and the block will depend on the storability and permeability of the reservoir system. When production logs are acquired, the well is put on production and the production is allowed to stabilize before the well is logged. Without sufficient knowledge on the reservoir system or understanding of the heterogeneity inherent in the reservoir, if production logs are run in this type of system, it is possible to acquire the logs during the matrix flow period. Any inference made from this analysis will not be representative of normal flowing conditions, i.e. when the well has had sufficient time for pressure equalization between the block and matrix system. Therefore the time frame during which production logging data is acquired becomes critical in understanding the behavior of the reservoir.
Abstract The Mangala oil field, discovered in 2004 is one of the largest onshore oilfields in India. The field is divided into five reservoir units and contains approximately 1.3 billion barrels of STOOIP. The field currently produces around 175,000 BOPD. The oil is highly viscous, with high paraffinic content, a high pour point, high Wax Appearance Temperature (WAT), as well as high wax dissolution temperature. In addition, high CO2 content, sand production and a high water cut are some of the other notable problems. Keeping this in mind, a combination of innovative technologies had been envisaged right from the development and appraisal stage of the field. The technologies used have been reviewed from a flow-assurance point of view and possible reasons for the selection of these techniques over other methods are also investigated and presented. The waterfloods, EOR pilots, artificial lift systems as well as surface facilities have been designed and implemented keeping in mind the nature of the crude. From a flow assurance point of view, techniques such as hot water injection, coiled tubing heater string, jet pumps etc. have been used extensively. A 670 km long pipeline has been laid from the field to Bhogat in Gujarat for transporting the crude. This pipeline is the world's longest independent heated section pipeline and makes use of another innovation called Skin Effect Heat Management System (SEHMS). A careful examination of these techniques can help us gauge whether they can be put to use to handle similar crudes in other parts of the world. This being a review paper, the working methodologies of flow assurance techniques used for the Mangala crude and the reasons for their success are studied.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.95)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (4 more...)
Low-Productivity Sand Characterization and Identification of Bypassed Oil and Water Source with Advanced Production and Pulsed Neutron Logging, A Unique Key for Improving Field Productivity
Van Steene, Marie (Schlumberger) | Abugren, Yosra (Schlumberger) | Joshi, Sameer (Schlumberger) | Thabet, Enas (Schlumberger) | Ahmed, Mohamed Mostafa (Khalda Petroleum Company)
Abstract An oil well with two perforated zones had an initial production rate of ~2,400 BOPD with water traces. Within 3 months, production decreased to ~1,000 BOPD and water cut increased to >25%. It was critical to identify the cause of decreasing productivity and increasing water cut to plan for remedial action. The reservoir was evaluated by integrating several answers obtained from reservoir saturation characterization through use of pulsed neutron capture and water-flow log data, as well as from conventional and advanced production logging. Production logging showed that water was sourced from the lower perforated interval, while only a small proportion of the flow came from the upper reservoir layer. Pulsed neutron logging confirmed a high amount of depletion in the zone below the lower perforation, with oil remaining in the upper part of the lower perforated zone and in the upper perforated zone. Bypassed oil was also found below the water-producing zone, confined between the oil/water contact and a thin shale break. This shale break is a major permeability barrier and allows lateral water movement through the high-permeability lower zone. A multilayer test carried out with production logging tools showed that the productivity index of the upper zone was only one-tenth that in the lower zone, due to either intrinsically low permeability or high skin factor. The multilayer testing also showed that of the two comingled layers, the upper layer had approximately one hundredth the permeability of the lower layer. Reperforation of the upper zone resulted in only minor improvement in well production, thus confirming that the low productivity was not caused by high skin factor, but was due to low permeability. From the testing, it is clear that to produce the oil from the upper zone, it will be necessary to produce the two zones separately, with different drawdown. Since similar conclusions were obtained in other wells in the field, these results provide a fieldwide strategy for improving field productivity.
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (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)
Abstract Water is injected in the hydrocarbon reservoir to serve two purposes, to maintain reservoir pressure and to displace oil as production proceeds in the reservoir. In recent years, smart wells coupled with reservoir simulation models are used to improve the results of water injection performance. High frequency data (pressure, flow rate, etc.) that is a product of the smart wells provide the basis for a closed-loop, fast track updating of the dynamic reservoir models. While high frequency updating of the reservoir model remains a challenge, there are emerging technologies that can make such objectives achievable. An integrated approach that combines analytical and numerical solutions with artificial intelligence and data mining is proposed to ultimately achieve the closed-loop, fast track updating system. This study is the first step in that direction. In this work the ability of analytical solutions to calculate reservoir water saturation profiles from field water cut data are investigated. Different flow regimes and reservoir geometries are considered during this study. Diffuse, segregated and capillary influenced flow models are analyzed in both one and two dimensional water injection using a commercial numerical simulator. Different analytical formulations are applied for each flow regime in order to reproduce simulation production data. For each model a specific relative permeability relation is assigned and tuned with the aim of matching water breakthrough time and water cut history. An accurate match is achieved between water saturation profiles generated by the analytical models and the results by the reservoir simulator. The influence of simple reservoir heterogeneity on the robustness of the analytical models is studied.
- North America > United States (0.68)
- Africa (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
- North America > United States > Arkansas > Smart Field (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Menggala Formation (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Bekasap Formation (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Bangko Formation (0.99)
Abstract The gas flow profile along the wellbore that includes contribution of all productive layers is an important piece of information for reservoir characterization and well management. It provides flow contribution from each producing interval along the wellbore, which is critical for optimizing well performance and maximizing gas recovery. The present work discussed determination of the rate profile from the pressure and temperature profiles in gas wells, which is significantly cheaper and more precise than the direct flow metering. An effective and robust algorithm for calculation of the rate and thermal conductivity profiles from the depth pressure and temperature distributions have been developed by tuning the mathematical model of non-isothermal gas flow in vertical well. The detailed sensitivity analysis shows that the inverse problem is well-posed. The initial values of rate and thermal conductivity for iterative minimization algorithm were obtained by averaging the values directly calculated from the measured pressure and temperature profiles. The initial values are shown to provide the final solution with good accuracy. It allows recommending the initial values for the estimates of the rate profile. Application of the algorithm to field cases shows good agreement between the directly measured and calculated rate profiles; the results are also consistent with flowmeter (PLT) data. It validates the proposed method.
- Europe (1.00)
- North America > United States > Texas (0.68)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
A Modelling Study of Severe Slugging in Wellbore
Malekzadeh, R.. (Department of Multi-Scale Physics, Delft University of Technology, P.O. Box 5, 2600 AA Delft, the Netherlands) | Mudde, R. F. (Department of Multi-Scale Physics, Delft University of Technology, P.O. Box 5, 2600 AA Delft, the Netherlands)
Abstract Developments in extended reach drilling and completion technologies allow to economically access a number of scattered small hydrocarbon pockets and will open up further opportunities for maximizing recovery from these fields. Effective use of these developments requires us to better understand the transient multiphase flow behaviour. Undulation is associated to horizontal wells with some degrees of deviation from the horizontal. The inclination angle could be a result of a lack of sufficient drilling control or could be designed on purpose, for instance, fish-hook wells, snake wells and undulating wells. A complicated and undulating trajectory may initiate severe slugging at the bottom of a wellbore. In this paper, OLGA, a commercial transient two-fluid multiphase flow simulator, and Cheng's inflow performance relationship were coupled together to characterize severe slugging. Simulation shows that severe slugging is formed at the bottom of the wellbore and moved up to the surface. Furthermore, it creates pressure pulsation at the bottom of the wellbore that can influence the reservoir performance.
- Europe (0.47)
- North America > United States (0.46)
- Africa (0.46)
Abstract This work investigates the flow structure development due to injecting water into the annulus of heavy oil pipe flow. Numerical simulation of the axisymmetric core annular turbulent flow is carried out using the standard k–ω model. The flow field and flow characteristics are investigated using FLUENT 6.3.26. The core annular flow of heavy oils-water in 15.24 cm diameter pipe, with three core diameters is considered. The influence of flow parameters upon the development of axial and radial velocity, turbulent kinetic energy, turbulent intensity, and strain rate profiles are investigated. Results show that flow development depends on the core to outer diameters ratio, oil viscosity, flow velocity, and water loading ratio. As oil's viscosity increases, flow structure develops faster towards fully developed one. Fully developed velocity profiles show uniform distribution in oil's core, while all velocity changes occur in water flowing in pipe annulus. The flow in the core region seems to be as rigid body carried by annular water flow. It has been demonstrated that major changes in flow structure occur at the oil-water interface.
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.49)
Abstract Diffra West is a medium size oil field in Muglad basin of Sudan. Oil is accumulated in multiple sandstone reservoirs of AD and BE formations. The field has been developed through conventional vertical wells and electrical submersible pumps (ESP's) are in use to lift the oil. Initial well productivity was very good. Currently the field is facing the challenge of high water cut which is masking the oil production and will result in lower recovery factor than envisaged in field development plan (FDP). Arresting the production decline by controlling the excess water production is crucial for achieving the targeted recovery factor. Well intervention programmes have given mixed results in view of inadequate diagnosis of source of water based on swab tests. This paper discusses the use of Production Logging Tool (PLT) for identification of water source and implemention of corrective action in order to revive and improve the oil production of an up-dip well in the Diffra West field. The decision to use the tool was guided by prudent reservoir monitoring and analysis after misleading swabbing test that would have led to permanent isolation of the main producing formation in this well. The field was producing oil with water cut of about 60% when it was decided to investigate the source of the water. Performance of updip wells was also affected due to high water cut. D5 which is an up-dip well was selected for this study due to its better position and expected higher gain after workover job (WOJ) compared to other wells. A swabbing test was used as an initial attempt to identify the water source which indicated that the lower formation, zone-6, was producing 100% water. Obvious decision is to isolate it. However, a through performance analysis of the wells in the field revealed that downdip wells were producing oil from this formation. Most of these downdip wells have commingled production from zone#6 and other zones. Swab test of zone-6 confirmed oil. Two recently drilled wells completed in zone-6 are also producing significant amount of oil. Therefore, the swabbing result of zone-6 in well D5 appears unreliable and inconclusive. Sometimes these inconclusive results are observed due to limited number of swabs. The ambiguity of the swab test together with the good performance of other wells completed in zone-6 warranted the resolution of this issue using PLT which is not so easy in wells completed with ESP. PLT results confirmed that zone-6 is producing significant volume of oil. This is quite consistent with the overall field assessment. Further, the PLT results indicate that most of the oil produced by this well is actually from this formation and other sub-layers are contributing only 25 to 35 percent. Thus a prolific contributing layer has not been prematurely isolated in this well due to improper analysis and this translates into reaping around 500 BOPD for the company. This is the first time of running PLT in ESP well in this field and the encouraging result will be useful in the analysis of remaining wells of the field.
- Africa > Sudan (1.00)
- North America > United States > Texas > Coleman County (0.24)
- Geology > Geological Subdiscipline (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Africa > Sudan > Muglad Basin (0.99)
- Africa > South Sudan > Muglad Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (4 more...)
Abstract It is often perceived that a cementing operation is the last step in the drilling process, but any cementer can tell you that cementing is the first step to a successful completions process. Proper displacement of mud during cementing operations is not only critical for successful zonal isolation, but also for achieving asset-management objectives for increasingly difficult-to-reach hydrocarbon reservoirs. One of the challenges in these complex wells is to provide uniform cement coverage across the entire zone of interest, especially in targeted zones where casing or liner is decentralized (off-center). In these situations, an uneven pressure differential from decentralization causes uneven flow of cement. The result is a much different top-of-cement (TOC) on the narrow side of the annulus versus the wide side of the annulus. Real-world negative effects of this phenomenon can include annular pressure build-up, the necessity of remedial squeeze work, and even well abandonment. A better understanding of fluid movement through the eccentric annuli can help predict the true TOC around decentralized casing. Therefore, a first-of-its-kind flow-predictor program was developed with the capability to accurately predict the TOC and corresponding fluid velocities for a three-component mud-spacer-cement system in eccentric annuli. It is based on a generalized mathematical model for pressure-drop prediction, developed using more than 1,700 experimental data points in physical models mimicking that of actual downhole geometries. Experimental data consisted of narrow and wide-side flow rates for 14 different fluids, within a density range of 8 to 21-lbm/gal, circulated in standard oilfield pipe and hole configurations ranging from 4.5-in. × 6.5-in to 9.625-in × 12.25-in. Standoffs varied between 12 and 82%. Yield point, viscosity, and shear thinning indices of these fluids varied between 0 and 50-lbf/100ft, 1 and 157-cp, and 0.4 and 1, respectively. Various simulations are shared to reveal the properties and parameters required to help achieve uniform flow around the annulus and a balanced TOC.
- North America > United States > Texas (0.29)
- North America > United States > Louisiana (0.24)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (0.92)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.91)