bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful High-Temperature, Water-Control Case Histories in Highly Naturally Fractured Carbonate Reservoirs
Authors: Mercado Modesto , Acuna Juan , Hernandez Ramon , Vasquez Julio , Soriano Eduardo , Caballero Carlos 
Published: February 2011

Abstract
This paper presents successful field implementations of a high-temperature polymer (HTP) for water and gas-shutoff applications in highly naturally fractured carbonate reservoirs with BHT &gt; 250°F. Fifteen case histories in a naturally fractured carbonate reservoir in Mexico (inland and offshore operations) are presented in which the HTP system was successfully applied to reduce water production. One-year, post-production data is reported for each case.
The HTP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 600 jobs have been performed with the HTP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing-leak repair. Originally, the HTP system had a limited working temperature range from 100 to 250°F. The upper placement temperature of the system was ~250°F as, above this temperature, pumping times were too short. A recently developed carbonate retarder allows reasonable placement times up to 350°F, without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system. The development results of this HTP system are also discussed.
The HTP system has been successfully applied to sandstone, carbonate, and shale formations requiring a conformance treatment. This system has been successfully tested to withstand a differential pressure of at least 2,500 psi and is resistant to acid, CO2, and H2S environments. To date, more than 100 jobs have been successfully performed worldwide with the HTP at temperatures higher than 250°F with the recently developed retarder. Because of the capability of the HTP system to withstand pressure, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others.
Extending Openhole Gravel Packing Capability: Initial Field Installation of Internal Shunt Alternate Path Technology
Authors: Hecker M. T. , Barry M. D. , Sweeney C. M. , Arnold S. P. , Yeh C. S. 
Published: February 2011

Abstract
High angle, openhole completions are often selected to maximize production and reserve capture from several non-homogeneous sand packages in a single wellbore. Many times, the wells will require some form of sand control. Standalone screen applications may often times be the most cost effective and simplest form of sand control, but the formation characteristics may dictate that a gravel pack is necessary. Circulating water packs, alpha-beta gravel packs, have been used worldwide, but may be challenged to achieve a complete gravel pack in certain applications. Alternate Path® technology (APT), using the current eccentric two by two (2x2) shunt system, has proven to be extremely reliable in completely packing the openhole annulus and delivering high rate, failure free openhole completions.
Although routinely deployed, the current eccentric 2x2 APT screens have both technical and operational limitations. These limitations may include:
Maximum shunt system working pressure of 3,000 psi which limits the packable length to ~3,200 ft pumping at 5 barrels per minute (bpm) Risk of plugging with two independent shunt tubes extending the length of the completion Complexity of rig site connection make-up as oriented connections and cross-coupling jumper tubes are required Deployment exposure dictates that an outer shroud must be incorporated in openhole applications to protect the shunt tubes
In order to overcome some of these limitations, while preserving all of the benefits of Alternate Path technology, a new generation of gravel pack screens was developed and successfully run utilizing Internal Shunt Alternate Path Technology (ISAPT). ISAPT extends openhole packable length, increases shunt tube redundancy across the entire interval, improves rig site installation efficiency, reduces deployment exposure, and provides a platform to incorporate specially designed shunt packers to provide true openhole zonal isolation.
This paper will discuss the key differences between the new ISAPT gravel pack screens and the current eccentric 2x2 APT screens as well as validation of key objectives from the first field installation.
Hitting Bull's-Eye with Time and Cost Estimates by Combining Statistics and Engineering
Authors: Hollund K. U. , Rosenlund H. , Akcora S. , Hauge R. 
Published: February 2011

Abstract
This paper describes the probabilistic model used for estimating time and cost of drilling and well operations (D&W) in Statoil. The model uses statistical methodology to assist sound engineering judgment. The drilling process is broken down to a level where it is possible to identify relevant reference data and to compensate for risk. Model assumptions are made based on large datasets and applied in situations with less data.
As this method was introduced in Statoil, the estimates on a portfolio level have gone from being systematically off, to hitting bull's eye. The time and cost distributions are heavy-tailed, so there will be many projects coming in below budget and there will be dramatic overruns from time to time. But for a portfolio of unbiased well estimates, the overall delivery is much more likely to meet the predictions. With a methodology that manages to produce unbiased estimates and present the range of uncertainty the decision makers are much better equipped when making decisions on current and future projects.
Real-Time Whirl Detector Aids Drilling Optimization
Authors: Minett-Smith D. J. , Stroud D. R. , Pagett J. M. 
Published: February 2011

Abstract
This paper describes the design, development and use of a real-time downhole whirl detection system employed in a latest generation point-the-bit rotary steerable system (Figure 1 shows the general arrangement of the steering system). The system employs a novel yet simple whirl detection sensor design which is sensitive to whirl yet passively filters out lateral vibration. Test results presented include full-scale BHA testing in a whirl simulation rig in conjunction with field trials at a drilling test facility.
In laboratory tests, fully developed backward whirl was produced such that whirl measurements from the onboard detector could be correlated with external laboratory sensors. The combined results of laboratory testing and field trials clearly demonstrate that this new whirl measurement system is much more effective at detecting backward whirl than traditional vibration sensors. In addition, the system was capable of both detecting whirl and measuring relative intensity.
The system has been successfully deployed in field applications to provide real-time warnings, enabling corrective changes in drilling parameters to mitigate down-hole conditions and thus maximize drilling efficiency. Case studies of real field applications in the North Sea, Middle East and Central Europe are included in which the detection system was successfully deployed to optimize the drilling process, through the prevention of undesirable BHA dynamics.
A Gravel Pack System That Allows Continuous Chemical Treatment to the Pay Zone Without Interrupting Production
Authors: Surveyor Nilufer , Amaral Anderson , Kaiser Garry , Faria Nervy , Gault Kerry , da Silva Mário Germino , Moura Heleno , Nuno João , Woodford Keith 
Published: February 2011

Abstract
The use of semisubmersible rigs, subsea trees and workovers in deepwater wells result in costly rig mobilization. Solving problems remotely, with an interventionless method, provides huge savings and fewer risks to the operator.
This paper focuses on the preparation of the first global installation of a gravel pack system that allows continuous chemical treatment pumping to the pay zone area without interrupting production. For wells with production issues such as barium and calcium sulfates causing obstruction of the sand-control screen base-pipe holes, this system will allow pumping of scale inhibitors (or any other chemical treatment) to the end of the horizontal well (toe) or to other parts of open-hole or cased-hole sections without needing to stop production.
This system was designed to allow continuous pumping of chemicals to inhibit scaling, corrosion and other production-related issues through one small-diameter flowline down to the interior of the sand control screens at two or more distinct parts of the well (while the well is still producing) or per a specific treating program. The number of injection nodes with the same flowline conduit can vary from well to well because the system incorporates zonal isolation with feed through capabilities, using reactive element packer and multiple sequential injection nipples technology. The first installation will require only two nodes.
The system allows for screen assembly and gravel pack installation in one trip, while the flowline conduit reconnects the upper string assembly, using an anchor reconnect seal assembly. For the horizontal open hole installation, the system also incorporates a high-flow liner system for flowline conduit/sensors protection and a special feed through quick connector to simplify certain steps in the assembly, and it allows for torque transmission in open hole deployment.
This paper will describe the system functionality, identify its main components and present the test program developed to demonstrate the system consistently, qualifying it for field installation.
Innovative Technologies Enable Fast, Accurate, and Detailed Completion Evaluation and Well Performance Analysis
Authors: Huang Hao , Burch Damian , Brown William , Yin Jichao , Long Ted 
Published: February 2011

Abstract
In this paper, we present a workflow that allows for accurate well and completion performance simulations to be conducted automatically. A number of innovative technologies are introduced to enable this workflow. First, a mesh generator was developed to automatically construct high quality, near-well meshes for wells with different deviation angles and variable producing segments. Second, the enriched finite element method, a new numerical technique, was used to provide detailed modeling of geological features (such as horizons, natural fractures, and no-flow boundaries) and completion characteristics (such as fractured completions and perforations) without having to manually construct a mesh that honors these complex geometries in detail. Third, a procedure was developed to fully couple the completion hydraulics and the near-well porous media flows.
To demonstrate the effectiveness of the new technologies, three application examples will be detailed: (1) a sensitivity analysis of partial completion or stimulation on well performance; (2) an evaluation of the productivity of a new sand control device that uses MazeFlo™ screen technology and contains a multitude of segmented production zones; and (3) the design of a multiply-fractured completion. Throughout these examples, guidelines on maximizing the efficiency of completed segment, stimulated well length, or fractured completion are summarized.
Development and Application of a Scale Inhibitor for Electrical Submersible Pumps Suitable for Very Cold Weather
Authors: Linares-Samaniego Sandra , Spicka Kevin 
Published: February 2011

Abstract
Many oil producers in the Rocky Mountains region, USA, make use of electrical submersible pumps (ESP) to assist the lift of produced fluids. This region of the country is well known for its very harsh winters, with outside temperatures as low as −40 °F (−40 °C).
ESP failures resulting in increased lifting costs due to workovers, lost oil, and logistics can be caused by many factors, including reservoir solids eroding the ESP or being trapped within the intake and pump stages, mechanical and electrical problems, and scale deposition. ESPs are particularly sensitive to calcium carbonate scale formation due to the extreme skin temperatures that can develop and often require continuous chemical injection to control this problem.
Calcium carbonate scale formation in ESPs is a well known contributor to ESP failures. Large pressure drops combined with high temperatures increase the risk of calcium carbonate deposition even in mildly scaling systems. Scale formation on the motor housing acts as insulation, preventing heat transfer from the motor to the well fluids, causing the motor to be insufficiently cooled. Any scale deposition on the pump impellers can cause an imbalance and vibration, degrading pump performance.
Continuous scale inhibitor treatment of ESPs to mitigate calcium carbonate scaling is a common practice. However, the choice of scale inhibitor requires careful consideration due to the high skin temperatures that can develop and can lead to inhibitor decomposition. Effective continuous treatment of ESPs during the winter months in regions where very low temperatures can be expected require product formulations capable of withstanding these harsh conditions without significant changes to their physical properties.
This paper presents and discusses, with the aid of laboratory and field data, the development and deployment of a thermally stable scale inhibitor suitable for treatment of ESPs that can also be deployed in very cold climates, along with the monitoring tools used to ensure effective treatment.
Using DTS Flow Measurements Below Electrical Submersible Pumps to Optimize Production From Depleted Reservoirs by Changing Injection Support Around the Well
Authors: Brown G. A. , Tiwari P. 
Published: February 2011

Abstract
In depleted reservoirs producing with high water cuts, it is often difficult to evaluate which intervals are producing oil. Such wells typically use electric submersible pumps (ESPs) to lift the fluids, so logging operations are limited. Even when logging is possible, identifying oil production that amounts to 5% or less from a zone producing water can be a challenge.
This problem can be addressed by installing fiber-optic distributed temperature sensors (DTS) below the ESP of a well producing oil with a high water cut from multiple reservoir intervals. Differentiating between water and oil production with a DTS system is not directly possible at such high water cuts; however, by switching the water injection support from surrounding injectors on and off, the reservoir intervals being supported by each injector can be identified and the injection pattern that maximizes oil production can be found. The information obtained will allow an operator to shut off the water-only producing intervals during a subsequent workover, resulting in increased oil production from the well.
This novel application of DTS monitoring below ESP pumps in depleted, high-water-cut wells and the low-cost monitoring procedure employed has the potential to significantly increase oil production in old oil fields under water flood.
Mature Field Revitalization: The Agbara Field Case History, Offshore Nigeria
Authors: Wane B. , Angelucci L. , Tealdi L. , Ogujawa J. , Fasaanu E. , Adekanye I. , Afolabi B. , Stanisci L. 
Published: February 2011

Abstract
The Agbara field is operated by Agip Energy and Natural Resources (AENR) under a service contract with the Nigerian National Petroleum Corporation (NNPC). The field lies approximately 30–40 Km from the coast in the Niger Delta offshore in water depth ranging between 55–70 m. It is located in the offshore depo-belt of the Niger delta basin where thick pliocene-clastic sequences of Agbada formation have been deposited in a deltaic–fluvio-marine to inner shelf environment.
Agbara field has been on production since June 1989 and its block, OPL 472, was converted into the Oil Mining Lease 116 (OML116) on September 1999. As at December 2009, the cumulative production is approaching 100 MMBBL with an average production of about 10,000 BOPD. With over twenty years of production, the Agbara case history presented in this paper constitutes a unique example of rejuvenation of a mature oil field. This paper will provide a description of single well optimization process that led to sensible production gain in a short time frame with about 40% increase in net oil production over a six months period as well as exploration and reservoir engineering practices that provided the basis for further exploration and development opportunities in the field. An extensive review of the field and reservoir description will be provided along with the development history. This paper, the first case history of Agbara focuses on both the well engineering and the reservoir engineering aspects. Suggested or implemented workflows and technology ranging from well and reservoir characterization, candidate selection, classical water shut off, stimulation to innovative new technology such as the use of Ejector (ENI R&D) and relative permeability modifiers are described. An overview of the future potentiality of such mature field is also described.
Real-Time Measurements of Spontaneous Potential for Inflow Monitoring in Intelligent Wells
Authors: Jackson M. D. , Gulamali M. Y. , Leinov E. , Saunders J. H. , Vinogradov J. 
Published: February 2011

Abstract
Spontaneous potential (SP) is routinely measured using wireline tools during reservoir characterization. However, SP signals are also generated during hydrocarbon production, because of gradients in the water phase pressure (relative to hydrostatic), chemical composition and temperature. We suggest that measurements of SP during production, using electrodes permanently installed downhole, could be used to detect water encroaching on a well while it is several tens to hundreds of meters away. We simulate numerically the SP generated during production from a single vertical well, with pressure support provided by water injection. We vary the production rate, and the temperature and salinity of the injected water, to vary the contribution of the different components of the SP signal. We also vary the values of the so-called ‘coupling coefficients’ which relate gradients in fluid potential, salinity and temperature, to gradients in electrical potential. The values of these coupling coefficients at reservoir conditions are poorly constrained. We demonstrate that the SP signal peaks at the location of the moving waterfront, where there are steep gradients in water saturation and salinity. The signal decays with distance from the front, typically over several tens to hundreds of meters; hence the encroaching water can be detected before it arrives at the well. The SP signal at the well is dominated by the electrokinetic and electrochemical components arising from gradients in fluid potential and salinity. Larger signals will be obtained in low permeability reservoirs produced at high rate, saturated with formation brine of low salinity, or with brine of a very different salinity from that injected.
Optimization of Production With ICV by Using Temperature Data Feedback in Horizontal Wells
Authors: Li Zhuoyi , Zhu Ding 
Published: February 2011

Abstract
Horizontal wells with intelligent completion have been widely used in the field today. With inflow control valves (ICVs) production can be optimized either on individual well or at large reservoir scale. A critical step in this procedure is to understand the inflow profiles along horizontal wellbores. To develop control and optimization strategies, permanent monitoring systems such as pressure gauges and temperature sensors have been deployed with downhole control valves to provide temperature or pressure data at real time, and to translate downhole flow conditions from these data.
The relationships between temperature and inflow distribution have been developed before in intelligent well models, and these models are very useful in locating water or gas entries, and obtaining better production performances. In this work we present a new idea of using temperature feedback to directly regulate flow control valves to achieve an approximate uniform flow distribution. Instead of detecting water or gas flow in a well with different thermal properties of fluids, we aim at regulating flow distributions by monitored temperature behavior to achieve optimal flow conditions. Early-time temperature and pressure data are used to estimate permeability and initial flow profiles along the well, then developed models are applied to generate a desired temperature profile that yields an evenly-distributed flow rate along the wellbore. ICVs are operated based on the interpretation from the initial temperature data, and temperature are monitored as it approaches the desired temperature profile. By this procedure, we will be able to produce a well at an optimal condition by choking down the flow rate at higher-permeability locations along the well and therefore to increase oil flow rate and delay early water breakthrough.
This paper explains the details of the procedure. Two examples are used to illustrate the application of the method; one is for a water-drive reservoir, the other is for a water-injection case. The results show significant improvement in well performance in both examples.
Combining Resistivity and Capture Sigma Logs for Formation Evaluation in Unknown Water Salinity: A Case Study in a Mature Carbonate Field
Authors: Cao Minh C. , Saldungaray P. , Belowi A. R. , Ong L. W. , Al-Mudhhi M. A. 
Published: February 2011

Abstract
Formation evaluation in unknown water salinity can be done by solving simultaneously for Sw and Rw from the logs of resistivity and sigma. This has not been used extensively in the past because the logs are often acquired on wireline at various times, leading to unknown invasion effects that complicate the integration of the deep-reading resistivity and the shallow-reading sigma logs. We will show that when the two measurements are free from invasion effect - and other interpretation parameters, such as porosity, Archie m and n, etc., are reasonably known - the technique works well and gives reliable Sw and Rw answers.
Both numerical and graphical solutions are presented. The numerical technique uses a minimization routine to solve for a salinity value that is consistent with Sw calculated from resistivity and from sigma. The salient point of the paper is the graphical technique that provides better insights into petrophysics than a set of equations. It uses an overlay of equi-saturation and equi-salinity lines superimposed on the crossplot of sigma versus resistivity data. The overlay dynamically changes as porosity, lithology, hydrocarbon type, temperature, and other parameters vary with depth. The graphical technique has several applications. For the interpretation, it is used to estimate Sw and salinity, and to identify zones of changing properties. For quality control, it is used to validate the input data. For processing, it is used to select parameters and analyze their sensitivities to the results. For job planning, it is used to validate (or invalidate) the application from input values of resistivity and sigma. The graphical technique provides a valuable aid to the petrophysicist and gives an independent verification of the numerical solution.
The proposed technique is illustrated with wireline induction and sigma logs acquired in several wells in a mature Middle East carbonate field. The wells under study are completed in open hole and are flowed during logging to ensure that both resistivity and sigma logs are free from invasion effect. The results of the resistivity-sigma technique compare very favorably with those of carbon-oxygen (C/O) logging. Moreover, production logging data confirmed the results and showed that the resistivity-sigma technique provides more robust answers than C/O in low-porosity formations (below 15 p.u.).