bluuebunny/crossref_metadata_2025_split huggingface dataset:
Initial Deployment of a New Design One-Trip Straddle System Resolves High Pressure Cross-Flow Problem in Water Injection Well in Algeria
Authors: Addoun M. , Maraf K. , Tighe M. , Bramwell J. , Snaas A. 
Published: September 2011

Abstract
The Ourhoud Field is located in Eastern Algeria and has some 60 producing wells with average production of approximately 600 m3/d/well (3,750 bopd/well). Pressure maintenance and production drive is provided by means of water injection at a total rate of some 55,000 m3/d (345,000 bwpd), and gas injection at 106 mmscfd. One water injection well provided problems to the continued effectiveness of the water injection program, because a thin isolated layer was acting as a thief zone taking some 30% of the injected water. When injection was shut down, the zone would crossflow into the zones above and below it at a rate of some 550 m3/d (3,460 bwpd). In order to correct this problem a straddle system was needed to shut-off this zone, allowing all of the injected water to enter the two desired layers thereby increasing both the volume displaced into these layers and the production rate of surrounding wells.
After a detailed review of available straddle options to shut-off the zone in the 7″ monobore completion, it was decided that a single trip system would provide the best chance of success by reducing the number of well entries required, the installation time, and the likelihood that continued shut-in cross-flow would have an adverse effect on a conventional two-trip straddle installation due to the protracted operation time. The chosen one-trip straddle (to set and retrieve) was a newly designed tool which had a model available in the required 7″ size that had undergone rigorous testing, but had not yet been used in the field. After extensive review of the design and testing of the tool, and evaluation of the risks associated with deploying a new design straddle against the advantages of a single trip installation, it was decided to run the first 7″ one-trip straddle on electric line in the well. In this paper the authors will review the well specifics, the design and operation of the single trip straddle, and the decision making process which resulted in its first installation. They will go on to describe the installation process in detail, and review the positive results achieved by the successful shut-off of the cross-flow situation.
Determination of Optimum N2 Rate for Unloading Gas Wells With Coiled Tubing
Authors: Zhou Y. , Smalley E. , Opel S. 
Published: September 2011

Abstract
Unloading gas wells with nitrogen (N2) is one of the most common applications of coiled tubing (CT). The unique feature of CT unloading, as compared to conventional gas lift, is that the gas injection depth can be changed continuously. Despite the large number of CT unloading jobs performed annually, the fundamental and frequently-asked questions such as optimum N2 rate and optimum gas injection depth as well as CT run into hole (RIH) speed remain. There are no simple and efficient methods that can be used to calculate these design parameters.
Unloading a water-loaded gas well with N2 and CT is a dynamic and transient hydraulic process. Before a gas well is significantly unloaded and the bottomhole pressure (BHP) is reduced significantly below the reservoir pressure, the effect of the reservoir on the unloading process can be neglected. As far as the simulation of multiphase annulus flow is concerned, the liquid phase comes solely from the original liquid that loads the well. This paper presents a simulation study focused on the main factors that affect the hydraulic behavior of the CT unloading process. The optimum N2 pump rate is determined based on the criterion of minimum BHP. Simulation results indicate that as N2 rate increases, the hydrostatic pressure in the annulus and BHP decrease significantly. However, further increase of the N2 rate beyond a certain threshold value would increase the friction pressure loss in the annulus and consequently increase the BHP, especially for gas wells where the CT/tubing or CT/casing clearance is small. It is found that as gas injection depth increases, the minimum achievable bottomhole pressure is decreased. Simulation results also indicate that for smaller wellbores where annular friction loss is a limiting factor, a smaller diameter coiled tubing string may be preferred. The challenges associated with liquid unloading in large and deviated wellbores are also discussed.
Automated Direct Fired N2 Vaporizer
Authors: Pugh T. , Roberts J. 
Published: September 2011

Abstract
This paper describes a Direct Fired Liquid Nitrogen Vaporizer Automation System (LN2 Vaporizer Automation) and the control equipment and techniques associated therein. This system has been developed over the last two years and has proven capable of controlling the discharge temperature of discharged nitrogen gas, across a broad range of rates and pressures in a wide range of ambient conditions, while controlling pollutants from the burner and providing for enhanced safety and reliability.
The key components of the system are:
a. Typical Direct Fired Liquid Nitrogen (LN2) Vaporizer System
b. A Program Logic Controller (PLC) with attached sensors and actuators
c. A Human Machine Interface (HMI) to allow for interaction with the system
The trials and jobs carried out to date are also briefly described in this paper, together with the current perceived strengths and weaknesses of the system.
Development of a Laser Scan Inspection Tool for Coiled Tubing
Authors: Kilambi S. , Tipton S. M. 
Published: September 2011

Abstract
Coiled tubing (CT) is used extensively in oil field applications where it can incur surface defects and imperfections. Fatigue cracks can nucleate prematurely from the surface flaws and reduce fatigue lives significantly. The influence of defects on fatigue life can only be assessed if accurate measurements of the defect geometry are available. Current CT inspection technology is based on magnetic flux leakage (MFL) which is useful in detecting flaws. But, MFL is incapable of quantifying defect geometry information. On the other hand, laser scanning inspection systems can provide direct measurements of the physical characteristics of surface flaws. This technology produces a set of 3D data points that represent a complete surface map of a flaw. Laser scan data have been successfully curve fit using a proven Taubin algebraic fit. With this basis, algorithms for determining critical defect parameters namely, defect depth, width, length, and projected cross-sectional area were developed. The results are within the specified accuracy of the laser scanner. The notch root radius can be estimated by curve fitting the flaw geometry at the root of the notch. The success of obtaining notch root radius depends on density of laser-scan data and absence of shadow effects. A laser scan system with lower incidence of shadow effects will further improve the effectiveness of a laser scanner inspection tool. This technology has tremendous potential as a general purpose inspection tool for oil field piping systems.
Comparison of Tracer Test Result and Analysis of Connectivity Injector and Producer during Pilot Waterflood Kenali Asam Zone P/1050
Authors: Suarsana I Putu , Badril Areza 
Published: September 2011

Abstract
Kenali Asam field, Pertamina EP working area, is located in West Sumatra of Indonesia. The field was discovered by NIAM in 1929. There are 285 wells were drilled which consist of 99 producing wells, 20 injector wells, and 8 dry well wells, and the rest are suspended wells. The reservoirs are layered reservoirs from shallow to deep zone, and 16 production zones. The oil was produced from primary stage to secondary stage. The secondary stage has been started by injecting water since March 1993. The water was injected to specific layer such as B/650, F/730, N/990, and S/1170. The peak production of primary recovery was 13,643 BOPD with water cut 14.4% in September 1954. Peak production of secondary recovery was 2105 BOPD with water cut 50% in October 1994.
Pertamina’s EOR department and Business Unit of Jambi field conducted pilot project to the zone of P/1050 with line drive pattern flood. The line drive pattern consist of 4 injection wells and 4 production wells. The pilot plan purposes are to evaluate the effect injection in that area to increase the energy of the reservoir, to sweep the oil to enhance the oil production. Before the water flood was commencing, chemical tracer was conducted to check the connectivity among the producers and injectors.
The chemical tracer IWT-2000 was injected to the KAS 63 (east area) for amount of 26 liters on November 17, 2007. The chemical tracer will be expected to flow to the monitor wells (KAS 227, KAS-028, KAS-164, KAS-39). Monitor wells are also considered as producer wells. The chemical tracers was detected in the monitor well (KA 39) after four months of injection from KAS 63. The rest of the monitor wells were not detected at all after 284 days of injections. But the connectivity analysis of injection and production showed that gross production, fluid level and bottom hole pressure increased in production wells.
In the west area, the chemical tracer IWT-1700 was injected to the injector KAS-73 in the mouth of 61 liter. The monitors wells, as well production wells, are KAS 35, KAS 38, KAS 243. The chemical tracer was detected in 3 months after injections in KAS 35. But there is no chemical detection in well KAS 38 and KAS 243 after 283 days. But, from the production analysis shows similar phenomena as in the east area. KAS 38 and KAS 243 showed the increment of gross production, pressure, and fluid level in the wellbore.
The waterflood pilot of layer P/1050 in Jambi area already conducted for couple years and the cumulative oil produced is more than 22 MBBO. This paper will described and evaluate the difference respond of fluid injection using chemical tracers and water. In the chemical tracer, it was detected the chemical concentration to evaluate the connectivity. Based on the water injection, it was evaluated the production performance to see the incremental of gross production, pressure and fluid level in the production performance.
Optimization of Completions in Unconventional Reservoirs for Improved Efficiency and Ultimate Recovery
Authors: Snyder D. J. , Seale R. A. 
Published: September 2011

Abstract
Over the last decade, an industry wide shift to unconventional plays has occurred due to advances in technology allowing for the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multi-stage fracturing are two technologies which have accomplished this.
The two main methods of horizontal, multi-stage completions currently used in unconventional reservoirs are cemented liner "plug and perf" and open hole, multi-stage fracturing systems. This paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal, multi-stage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Case study examples are presented from a variety of unconventional reservoirs including shale, tight sandstone and tight carbonate formations.
Operators working in a number of unconventional reservoirs, such as shales and other tight rock formations are experiencing faster than expected production decline rates, resulting in reduced long-term, ultimate recovery. This may be in part due to the abandonment of good fracturing practices with the advent of horizontal, multi-stage fracturing. Issues such as near wellbore conductivity, flowback, and fracture tortuosity, which can have a significant effect on the long-term production of wells, need to be considered when choosing a completion method, particularly for unconventional reservoirs.
Unconventional plays are becoming a significant part of the oil industry today and will become a bigger part in the future. It is important that the reservoirs are completed optimally to achieve maximum recovery. The information provided in this paper is applicable to unconventional resource plays worldwide.
Spoolable Coiled Tubing Spears: Recovering Subsea Wells After Emergency Shutdowns
Authors: Guidry C. , MacDonald A. , Kelbie G. 
Published: September 2011

Abstract
A UK North Sea operator presented a challenging opportunity for the development of a contingency recovery system to be designed for deployment from an intervention vessel. The main requirement of the contingency tool was that it be capable of recovering coiled tubing that is subsequently left in a subsea well after previously operating an emergency shutdown (ESD) system and securing the well.
Typically, when an ESD operation must be performed, requirements demand that the vessel be unlatched from the subsea wellhead within 60 seconds. When the vessel returns, the operator has to recover the coiled tubing that was left in the well. Unlike conventional operations, for this vessel-deployed endeavor, the injector head is located over the moonpool, a large opening in the middle of the vessel that gives the operator subsea access. Unfortunately, the moonpool poses an inherent human risk; thus there exists the desire to limit human interaction in this type of operation.
To reduce the human risk involved, a spoolable spear system that eliminates the need to break out the lubricator/riser multiple times was engineered. The system was designed to enable retrieval of the sheared coiled tubing and recovery of the coiled tubing and connected tools to the work reel without breaking a lubricator/riser connection. Specifically, after a dressing run is completed, the spoolable coiled tubing spear is able to stab into the dressed open end of the coiled tubing and recover the coiled tubing string back through the injector head and back onto the work reel.
With an ever increasing focus on safety, particularly offshore safety, this spoolable spear system presents an opportunity to reduce human intervention in work locations and to significantly reduce the risk of injury. A reliability feature of the contingency system is that all components stressed during operation are to be replaced after each run, making it a one-run system. Multiple sizes of this coiled tubing recovery system have been developed for efficient and effective interventions while encouraging footprint minimization. Field-testing details will be reviewed and discussed during the associated presentation.
Modelling Residual Oil Saturation in Miscible and Immiscible Gas Floods By Use of Alpha-Factors
Authors: Bourgeois Marcel J. , Thibeau Sylvain , Guo Jia 
Published: September 2011

Abstract
For miscible gas flooding, it has been documented that forcing a residual oil saturation Sorm is helpful to make the compositional simulations more realistic. Our recent experience is that this concept can be extended to near-miscible and even immiscible gas floods. For CO2 floods, we have found that preventing this residual oil saturation from being stripped by the gas corrects overestimation of the recovery factor in compositional simulation, even at pressures lower than the miscibility pressure.
This residual oil saturation can be implemented with the use of Alpha-Factors (named also transport coefficients). Their physical meaning will be discussed, and also a way to generate them. Our method is to use an iterative process based on a PVT package, and analytical equations allowing to compute their endpoints are given.
Also some limitations of the approach will be discussed, such as grid size dependence, a weak pressure dependence and a strong dependence on the injected gas composition.
Petro-Elastic Parameters Effects on History Matching Procedures
Authors: Souza R. M. , Santos M. S. , Schiozer D. J. 
Published: September 2011

Abstract
Rock physics models are the quantitative link between the seismic information and reservoir properties. Thus, several authors have been used this link to develop methodologies aiming to integrate seismic derived information and production history matching. Nevertheless, there are significant uncertainties related to petro-elastic parameters definition and its effects on typical history matching results.
This paper evaluates this problem through the application of two history matching procedures. The empirical allowed range of petro-elastic parameters regarding fluid and rock behavior, such as temperature, salinity and porosity, mineral and dry rock modulus, respectively, are combined to define different data sets. Each set defines petro-elastic models to be coupled to a numerical reservoir model providing synthetic impedance distributions.
These sets of impedance are then used in two different integrated history matching techniques. First, each set is combined with production data defining a global objective function to be minimized and provide a new horizontal permeability distribution resulting in an updated model. Secondly, a constrained inversion procedure is applied to convert impedance into saturation and pressure distributions. These maps indicate the optimization regions and the quantitative seismic information to improve the global objective function minimization accuracy aiming to derive a new permeability distribution. Thus, permeability and bottom-hole pressure from the updated reservoir models are compared to evaluate the several combinations of petro-elastic parameters effects.
The major goals of this paper were to quantify the petro-elastic parameters definition effects on history matching procedures, indicating which of them is more sensitive to their variations. Furthermore, it was possible to assess their individual impact in the history matching results and highlight the importance of a careful definition of these parameters and its coherent integration with fluid flow models. This approach also contributes to quantitative integration aspects of oil reservoir development and management.
New Approach for Successful Sidetracking of a Cement Plug in Salt and Subsalt Wells at High Inclinations Using Rotary Steerable Tools and Reamers
Authors: Chamat E.. , Leavitt T.. 
Published: September 2011

Abstract
Drilling for hydrocarbon deposits beneath the salt canopy in the Gulf of Mexico (GOM) has become common in deepwater; however, such drilling is made more difficult because of geological events that can cause difficulties in the drilling process, leading to expensive sidetracks or unwanted extra casing operations. To make operations economically feasible and to accomplish demanding rig utilization schedules, wells are planned to be drilled using one bottomhole assembly (BHA) from casing to casing at optimized rates of penetration (ROP), accurately placing the well while minimizing drilling and geological risks. Sediment inclusions, salt creep, rubble zones, narrow mud-weight windows along with well control events and mud losses, wellbore stability events and thin tar zones are some of those geological events found when drilling through salt and subsalt. Rotary steerable systems (RSS), reamers and synthetic oil-base muds have provided solutions to most of these challenges.
This paper presents case histories of two deepwater wells drilled in the GOM. The first case, describes how, after having drilled through a long salt interval, tar was unexpectedly penetrated, requiring sidetracking in two different bypasses at high inclinations. Previous experiences of the operator and the industry indicated that tar cannot be detected in seismic data or accurately correlated from well to well because its short extension, and its presence could prevent reaching programmed total depths. Because of the inability to drill through the few sequences of tar intervals, it was required to sidetrack the well on two different occasions at high inclinations to reach the planned borehole total depth with the planned casing program.
The second case presents the history of the deepest sidetrack performed in the GOM. This well was sidetracked for geological resons, subsalt at 28,822 ft measured Depth (MD), off of a cement plug.
A push-the-bit RSS (and a reamer in the first case history) was used to sidetrack off cement plugs in both cases. Both cases were planned to sidetrack on the low side; however, this practice commonly used for downhole motors, proved ineffective in both wells. Both cases indicated that good cement was placed in the lower side of the hole, and so a setting to the right of the high side of the toolface was used successfully to deflect the wellbore. The technique, difficulties, and best practices resulting from drilling these high inclination sidetracks are addressed in this paper.
Increased Success Rates for Squeeze-Cementing Using a Surfactant Soak -The Vital Role of Surfactant Concentration
Authors: Erwin Erwin , Dewanto Christianto Widi 
Published: September 2011

Abstract
Historically, in the Melibur oil field in Sumatra, Indonesia, typically more than two squeeze-cement jobs are required before cement isolation is achieved. Eventhough the goal for water-zone shut-off is eventually achieved, we tie-up staff and equipment an the cost per water-shut-off is high.
This circumtance challenged us to try a different squeeze cementing technique in order to achieve water-shut-off after one squeeze cementing job.
We considered various different approaches, such as modifying the cement recipe, injecting water-conformance chemicals and a surfactant soak.
Fluid-compatibility tests were performed, where various chemicals were added to a mixture of formation oil and water, to see which chemicals were most effective to de-emulsify the oil-water mixture. The idea was that cement would better bond with the formation water if it were separated from the formation oil.
Knowing the wetting characteristics of the reservoir rock is a must before deciding to use surfactant. The chosen surfactant must be water-wet and be non-damaging to the formation. We found an anionic surfactant was best for our formation.
Next came the hardest part, deciding the concentration of surfactant. In the lab, we increased the surfactant concentration gradually from 0.5% to 4% to see the effect on the cement bond. We found that if the surfactant concentration was too high, then the setting of the cement was retarded, and the additional waiting time was unacceptable for the field operation. We found that a 3 % surfactant with a 12-hour soak in the reservoir was best.
An additional benefit of the surfactant was it changed the oil-wet rock into water-wet rock, and thereby mobilized oil that was trapped near the rock surface. This made it easier for cement to bond with the formation.
This surfactant soak technique has been performed on seven wells to date. The first well required two squeeze-cement jobs to isolate the water, and the remaining six wells required one squeeze-cementing job. The failure in the first well was thought to be due to the incomplete mixing of the surfactant in our homemade batch mixer. After the first job, the batch mixer was modified with a more powerful hydraulic motor and a different agitator blade.
This technique is considered a big success, and is now standard practice in the Melibur oil field. This project demonstrates that old problems can be solved cheaply and effectively if we turn out thinking upside down.