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Collaborating Authors
Results
Summary Oil and water production data are regularly measured in oilfield operations and vary from well to well and change with time. Theoretical models are often used to establish the production expectation for different recovery processes. A performance surveillance understanding can be developed by comparing the field production data with the production expectation. This comparison generates quantitative or qualitative signals to determine whether the producer meets production expectations or the producer is underperforming and appropriate operational action is required to address the underperformance. The case study is for the South Belridge diatomite in California. This hydraulically fractured diatomite reservoir is currently under waterflood and steamflood. A methodology is proposed to establish the production expectation from historical production data. For primary depletion, the formation linear and bilinear flow models are applied to producers with vertical hydraulic fractures. For waterflood, an analytical method derived from the Buckley-Leverett displacement theory is used. Those analytical methods can predict production and provide surveillance signals for producers in the primary and waterflood recovery stages. For steamflood, a semiquantitative performance/surveillance criterion is proposed on the basis of understanding the mechanistic oil banking concept and reservoir simulation results for steamflood and waterflood. With those models representing expected production performance, an integrated flow regime diagram is proposed for production surveillance. A performance expectation can be developed for an individual producer. A significant overperformance relative to the expectation normally indicates changes in the recovery mechanism or improvement in sweep efficiency. A significant underperformance usually signifies an operational issue that requires correction to optimize the production performance. In the case study, the surveillance methodology for producers under primary depletion, waterflood, or steamflood is demonstrated by use of historical production data. In addition, water channeling between injectors and producers and its impact on production performance are discussed. On the basis of this surveillance methodology, some operational actions were proposed, and successful results are demonstrated. Examples of forecast for an individual producer in the primary depletion stage and field scale prediction in the waterflood stage are provided. Application indicates that the proposed methodology can serve as a convenient and practical tool for reservoir surveillance and operational optimization.
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Belridge Field > Tulare Formation (0.98)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Belridge Field > Diatomite Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production data management (1.00)
A Comprehensive Theoretical and Experimental Study on Fluid Displacement for Oilwell-Cementing Operations
Aranha, Pedro Esteves (Petrobras) | de Miranda, Cristiane Richard (Petrobras) | Cardoso, Walter F. (Petrobras) | Campos, Gilson (Petrobras) | Martins, André Leibsohn (Petrobras) | Gomes, Frederico C. (Pontificia Universidade Catolica do Rio de Janeiro (PUC-Rio)) | de Araujo, Simone Bochner (Pontificia Universidade Catolica do Rio de Janeiro (PUC-Rio)) | Carvalho, Marcio S. (Pontificia Universidade Catolica do Rio de Janeiro (PUC-Rio))
Summary Displacing fluids in downhole conditions and for long distances is a complex task, affecting several steps of well construction. Cementing gains relevance the moment that fluid contamination compromises cement-sheath integrity and consequently zonal isolation. Density and rheology design for all the fluids involved is essential to achieve operational success. Properties hierarchy and preferred flow regimes have been empirically defined and tend to provide reasonable generic results. Challenging operations, including ultradeep waters and their narrow operational-window scenario, require further knowledge of the physics involved to prevent undesirable events. This paper presents the in-house development of software for annular miscible fluid displacement that analyzes fluid displacement in typical vertical and directional offshore wells, for Newtonian and non-Newtonian liquids and laminar- and turbulent-flow regimes. The formulation proposed provides accurate results for a wide range of input parameters, including the cases in which the ratio of the inner radious to the outer radius of the annulus is small. The computational work is validated by unique results obtained from an experimental test rig where detailed displacement tests were conducted. Contamination degrees were measured after the displacement of a sequence of fluids through 1192 m of vertical well. Effect of fluid-density and rheology hierarchy, flow regimes, and displacement concepts was investigated. The results provide relevant information for the industry and fundamental understanding on displacement of Newtonian and non-Newtonian liquids through annular sections.
- North America > United States (1.00)
- South America > Brazil (0.96)
- Research Report > New Finding (0.40)
- Research Report > Experimental Study (0.40)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.93)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (0.88)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.70)
Summary The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
- North America > United States (1.00)
- Europe > Netherlands > North Sea > Dutch Sector (0.50)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek License > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek Field > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > Coevorden Field > Z3 Carbonate Formation (0.98)
- (6 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (7 more...)
Surge-and-Swab Pressure Predictions for Yield-Power-Law Drilling Fluids
Crespo, Freddy (University of Oklahoma) | Ahmed, Ramadan (University of Oklahoma) | Enfis, Majed (University of Oklahoma) | Saasen, Arild (Det norske oljeselskap and University of Stavanger) | Amani, Mahmood (Texas A&M University at Qatar)
Summary Surge and swab pressures have been known to cause formation fracture, lost circulation, and well-control problems. Accurate prediction of these pressures is crucially important in estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham plastic (BP) and power-law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids. This paper presents a new steady-state model that can account for fluid and formation compressibility and pipe elasticity. For the closed-ended pipe, the model is cast into a simplified model to predict pressure surge in a more convenient way. The steady-state laminar-flow equation is solved for narrow slot geometry to approximate the flow in a concentric annulus with inner-pipe axial movement considering yield-PL (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, regression techniques were applied primarily to develop a simplified model (i.e., dimensionless correlation). The performance of the correlation has been tested by use of field and laboratory measurements. Comparisons of the model predictions with the measurements showed a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to the measurements because of the application of a more realistic rheology model. The correlation and model are useful for slimhole, deepwater, and extended-reach drilling applications.
- Europe (1.00)
- Asia (0.68)
- North America > United States > Texas (0.29)
- North America > United States > California (0.28)
- Research Report > Experimental Study (0.67)
- Research Report > New Finding (0.46)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (2 more...)
Field Redevelopment Optimization to Unlock Reserves and Enhance Production
Al-Nabhani, Salim (Petroleum Development Oman) | Al-Marhoon, Nadhal (Petroleum Development Oman) | Al-Rubaiey, Faisal (Petroleum Development Oman) | Al-Kalbani, Ammar (Petroleum Development Oman) | Al-Mandhari, Badar (Petroleum Development Oman) | Al-Hattali, Ahmed (Petroleum Development Oman) | Al-Hashami, Ahmed (Petroleum Development Oman) | Hassan, Hany (Petroleum Development Oman)
Abstract A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude"QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for"H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields. Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of"H" area cluster by developing more reserves and handling the water production.
- North America > United States > Texas (0.28)
- Asia > Middle East > Oman (0.26)
Abstract The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months. Typically the well by well process is as follows: Well testing Amalgamation of the well test data with down hole gauge and ESP controller data Analysis of the data to find the existing operation conditions Analysis of the ESP pump curve operating point and optimisation limitations Sensitivity studies in software to assess the optimum frequency and WHP Notification for the field operations to action the changes Further well tests to verify the new production data. Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management. Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time. Each well’s processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production. This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Asia > Middle East > Kuwait (0.15)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.71)
- Well Completion (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (0.88)
Abstract The Middle Minagish Oolite Formation is 450 to 550 feet thick interval of porous limestone reservoir, composed of peloidal/skeletal grainstones with lesser amount of packstone, oolitic grainstone, wackstone and mudstone in Umm Gudair field, West Kuwait. It is characterized by small scale reservoir heterogeneity, primarily related to the depositional as well as diagenetic features. Capturing reservoir properties in micro scale and its spatial variation needs special attention in this reservoir due to its inherent anisotropy. Reservoir properties will depend on the level that we are analyzing on reservoir (millimeter to meter scale). Here we used Electrical Borehole Image (EBI) and Nuclear Magnetic Resonance (NMR) to capture small scale feature of Umm Gudair carbonate reservoir and compared them with core data In present work, reservoir properties (including texture, facies, porosity and permeability) interpreted by the EBI shows good match with NMR driven properties and core data. Textural changes in image logs also match well with pore size distribution from NMR logs. Further highly porous zones which are considered either due to primary porosity or vugs match with larger pores of NMR logs and these corroborates with also core derived porosity. A good match has been observed between EBI, NMR and cored derived porosity. Permeability calculations have also been made and compared with core data. A detail workflow has been developed here to interpret reservoir properties on un-cored wells, where only low vertical resolution data is available. This technique is quite useful to identify the characters and mode of origin highly porous zones in reservoir section which are generally not identifiable by low resolution standard logs. This workflow will allow us to interpret the heterogeneity at high resolution level in un-cored wells, as results are validated with integration of EBI, NMR and core data.
- North America > United States > Texas (1.00)
- Asia > Middle East > Kuwait (0.88)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (40 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (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 > Borehole imaging and wellbore seismic (1.00)
Unconventional Use of Production Logging Technology
Chaudhary, S.. (ONGC Limited) | Murty, M. S. (ONGC Limited) | Bora, S.. (ONGC Limited) | Chandra, Y.. (ONGC Limited) | Singh, P. P. (ONGC Limited) | Pandey, R. K. (ONGC Limited) | Bhatt, U. C. (ONGC Limited) | Verma, V.. (Schlumberger) | Ogra, K.. (Schlumberger) | Pandey, A.. (Schlumberger) | Gupta, S.. (Schlumberger) | Sinha, R.. (Schlumberger)
Abstract Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Abstract Significant advances have been made in formation testing since the introduction of wireline pumpout testers (WLPT), particularly with respect to downhole fluid compositional measurements. Optical sensors and the use of spectroscopic methods have been developed to improve sample quality and minimize sampling time in downhole environments. As a laboratory technique, spectroscopy is a ubiquitous and powerful technology that has been used worldwide for decades to measure the physical and chemical properties of many materials, including petroleum, geological, and hydrological samples. However, laboratory-grade, high-resolution spectrometers are incompatible with the hostile environments encountered downhole, at wellheads, and on pipelines. Only limited resolution techniques are available for the rugged conditions of the oil field. This paper introduces a new optical technology that can provide high-resolution, laboratory-quality analyses in harsh oilfield environments. A new technology for optical sensing, multivariate optical computing (MOC), has been developed and is a non-spectroscopic technique. This new sensing method uses an integrated computation element (ICE) to combine the power and accuracy of high-resolution, laboratory-quality spectrometers with the ruggedness and simplicity of photometers. Many modern sensors typically merge the sensor with the electronics on an integrated computing chip to perform complex computations, resulting in an elegant yet simplistic design. Now, optical sensing using ICE features an analogue optical computation device to provide a direct, simple, and powerful mathematical computation on the optical information, completely within the optical domain. Because the entire optical range of interest is used without dispersing the light spectrum, the measurements are obtained instantly and rival laboratory-quality results. A proof of concept MOC with ICE has been demonstrated, logging more than 7,000 hours, in nearly continuous use for 14 months. Oils with gravities ranging from 14 to 65°API have been measured in downhole environments that range from 3,000 to 20,000 psi, and from 150 to 350°F. Hydrocarbon composition measurements, including saturates, aromatics, resins, asphaltenes, methane, and ethane, have been demonstrated using the MOC configuration. As compositional calculations therein, GOR and density are validated to within 14 scf/bbl and 1%, respectively. The paper discusses the details of the new ICE-based sensor and describes its adaptations to downhole applications.
- Research Report (0.67)
- Overview > Innovation (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- (3 more...)