bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Analytical Model Coupled With Data Analytics to Estimate PDC Bit Wear
Authors: Liu Z. , Marland C. , Li D. , Samuel R. 
Published: June 2014

Abstract
The increasing complexities of wellbore geometry imply an increasing potential of damage resulting from downhole bit wear. Although the locations of critical bit wear can be difficult to predict, the quantification of the actual bit teeth/cutter wear is important to achieve reduced cost per foot and predictable bit failure.
There is no acceptable universal mathematical model that describes bit wear accurately because of the complex nature of downhole conditions. Usually, either analytical models or real-time data analytics are used separately to estimate and predict bit wear. Combining both methods and using them simultaneously is an efficient way to address this limitation. This paper presents a new simple analytical bit wear model coupled with data analytics using real-time gamma ray data to suppress the uncertainties of the interacting formation properties and other intervening variables. The fractional bit wear of polycrystalline diamond compact (PDC) bit cutters is obtained from the geometric correlation between height loss and the cutter volume loss. The volume loss of cutters is assumed to be proportional to weight on bit (WOB), cutter sliding distance, rock strength, and rock quartz content.
The paper presents a field example to predict and estimate the bit wear using actual data. Gamma ray and rate of penetration (ROP) data of the initial drilling section are used to train the model to quantify the influence of formation strength interaction with the analytical model. Then estimation of ROP using the new bit wear model was carried out using actual field drilling parameters. The calculated ROP profile closely matched with the actual data within reasonable accuracy of less than 5%. Specific procedures are proposed for effective prediction of ROP and bit life.
Novel MPD Technology Applied in Ultradeep Waters in the Caribbean
Authors: Malt R. , Figuera R. , Marcano A. , Baez A. 
Published: June 2014

Abstract
Ultra deep water presents the most challenging conditions during drilling operations. When weak carbonates increase the likelihood of fracturing a formation, the challenge increases further still. High hydrostatic pressures, due to the long riser as well as the narrow gap between pore and fracture pressures, add to the complexity. Performing successful cementing operations is equally challenging.
This paper describes the drilling of a well at approximately 2200m in the eastern GoM. The formations were carbonates with potential for high-to-total losses. The rig was a new Sixth Generation DPMODU. To manage the BHP and avoid or reduce losses, the rig had been equipped with a new type of MPD system. This is a pumped riser system, with the pump mounted approximately 400m below the bell nipple. The pump reduces the riser level in a precisely controlled manner to manipulate the BHP as required.
Due to a very weak 20"shoe the 17 ½" section had a drilling window of only 0,3ppg. The MPD system was used to drill the section with nearly constant BHP, compensating for the ECD by managing the hydrostatic column level while drilling, and bringing the level back up for connections. No losses were seen. The same applies for cementing of the 13 3/8 casing.
The main focus in this paper will be the 8,5"section where this MPD system again was necessary due to potential for severe losses. The section was drilled with riser level actively managed to control the BHP. On connections riser level was increased to account for the loss of annular friction, thus always keeping the BHP under control. It soon became evident that this formation could not have been drilled conventionally as weak zones were penetrated at the start of the section. Loss pressure was 8,4 ppg. Drilling with returns was still required in order to get the required geological information from the well, which was achieved. As drilling proceeded a normal-pressured zone was encountered. This paper will describe the planning and drilling operation of the mentioned ultra-deepwater well with focus on the very challenging 8,5" section
Assessment System First Gas Artificial Lift by Using (Coiled Tubing) in Punta de Mata District Production Executive East
Authors: Almendras J. , Torrealba J. , Tineo R. , Arcia L. 
Published: June 2014

Abstract
Carito field is located in Punta de Mata, Monagas state, in the East of Venezuela. This field is exploited since 1.993, and assisted by gas injection as a secondary recovery mechanism from 1996. The well CRC-19 started its activity in July 2005, with 744 STB/D; 0,617 MMSCF/D; GOR= 829 SCF/STB; °API= 23.8; %Water= 0 and 6.900 psi of initial reservoir pressure.
In May the 13th 2013, after a stimulation treatment, the last production test showed that the well CRC-19 was producing 580 STB/D, 0.1 % Water, with 350 psi of WHP and 6.200 psi of static Bottom Hole Pressure (BHP).
According to the drawdown of the well, using an additional lift artificial method was evaluated. A low Gas Relation Oil (GOR) and the availability of a high pressure surface gas source were the main factors to define Gas Lift Systems (GLS) as the best lifting method for this well.
In July 2.013, CRC-19 was the first well of Punta de Mata District completed with artifcial lift. This configuration includes a coiled tubing positioned inside the hole at 12.000 feet to provide the gas from the injector wells at 7.500 psi.
This technique was suitable to avoid both the rig and the 3 months production shutting necessary to instal the conventional gas lift mandrels.
During one month the well CRC-19 has been producing 1.600 STB/D, assisted by 2,3 MMSCF/D, which means a 175% of oil production rate increment, besides the benefit of not needing a rig to clean the well, since the coiled tubing is retriable.
Fiber-Optic Technology Reduces Production Logging Limitations in Complex Conditions: Case Studies from Mexico
Authors: Lopez S. Perez , Hernandez I. Diaz , Luvio D. Tornez , Garcia Ortega M. A. , Sookram N. S. , Hernandez I. Perez , Mendoza Joly J. E. 
Published: June 2014

Abstract
Production logging forms an integral part of reservoir monitoring and problem diagnosis during the productive life of a hydrocarbon field. However, conditions in many wells make acquiring logs difficult, if not nearly impossible. An innovative conveyance and acquisition system applied in four non-conventional operations from Mexico has made it possible to acquire logs that would not have been attempted without this technology.
The new technique uses coiled tubing equipped with optical fibers to acquire real-time measurements from the downhole logging string. The advantages of this conveyance option include a lighter, more portable coil, compared to traditional coil tubing with logging cable, the capacity to pump fluids through the coil, and no need for a logging unit. This novel technology can be used for production logging in horizontal or high angle wells, especially when a lighter coil is needed to get down, on offshore platforms when space is limited, to lift and log wells that do not flow naturally, and in wells that need cleaning out before logging because the same coil can be used for both purposes.
Each of these cases from Mexico illustrates a unique application of the system. The first involves an offshore well, which was cleaned out, lifted with nitrogen and logged to obtain a production profile, with a single coil. The second is a production log for water entry diagnosis in a well with two branches, one horizontal and the other vertical. The third well, a highly deviated barefoot completion, does not flow because of water accumulation in the wellbore, but was cleaned out, lifted and logged with fiber-equipped coil. The fourth is a horizontal shale gas well for which the same coil was used to clean out and then run an advanced production logging string.
These selected cases highlight the significant extension in the range of application of production logs and well diagnosis with the introduction of this new system, especially in complicated cases or in wells that need to be lifted to flow. The technology also reduces the amount of resources required on location, improving logistics, saving time, and ultimately lowering costs for operators.
Geomechanical Modeling of Wellbore Stability in Anisotropic Salt Formation
Authors: Yi Wang H. , Kumar A. , Samuel R. 
Published: June 2014

Abstract
Exploration drilling is venturing out into deeper regions of water. While exploring these deeper water depths, large hydrocarbon deposits have been found below salt formations. These reservoirs are located in formations called "pre salts," which are located below the salt formations. Pre-salt reservoirs have been found in Brazil, the Gulf of Mexico, West Africa, and the North Sea. Completions in salt formations can be difficult owing to the creep behavior that the salt formations exhibit. Creep behavior results from the instability of the salt formation, which causes a slow flow and results in permanent deformations. Creep and deformation occur over time and are initiated once the salt formation has been penetrated. Completion of the wellbore does not stop formation creep. The constant creep of the formation causes excess stress on the well completions, which will eventually cause the casing to collapse. This study presents a geomechanical model, which can be used to predict the in-situ casing stress in a salt formation throughout the lifetime of a well. The model incorporates various parameters, like formation and wellbore pressure and formation temperature, as well as casing, cement, and rock properties. In addition, the impact of variations in temperature around the wellbore, drawdown pressure during production, the shape of the wellbore, and formation anisotropic properties are also investigated. The results indicate that many well-established factors that affect wellbore stability in a conventional and non-creep formation may not be valid in salt formations that exhibit creep behavior.
Application of Assisted Optimization to Aid Oil Exploitation Strategy Selection for Offshore Fields
Authors: Gaspar Ana T. , Barreto Carlos E. , Muñoz Mazo Eduin O. , Schiozer Denis J. 
Published: June 2014

Abstract
Decision-making processes for selecting an oil exploitation strategy can be complex due to the high number of variables to be optimized. Many times, it can be unfeasible to search an optimal solution by evaluating a high quantity of variables simultaneously. In this case, assisted methods that involve engineering analyses and mathematical optimization algorithms are an alternative to obtain a good solution. This paper shows the application of an assisted method to optimize a large number of variables of an oil exploitation strategy. The proposed methodology is to order and combine different optimization procedures with practical engineering analysis. The optimization variables include number and position of wells, platform capacities, wells opening schedule and wells shut-in time. The methodology is applied to a reservoir model based on a Brazilian offshore oil field to discuss the results obtained. Results indicate an efficient procedure for evaluating deterministic scenarios, suggesting optimization procedures for each decision variable and enabling the achievement of good quality solutions with a reasonable number of simulation runs. This is useful in many practical cases, mainly those, which require runs with long simulation time.
A Novel Approach to Analyzing and Managing Well Spacing and Density in Boscán Field, Western Venezuela
Authors: Plaza Rut , Pernalete Marta , Smith Bruce , Suman Balram , Chen Chun , Mayank Kumar 
Published: June 2014

Abstract
The Boscán field is estimated to contain as much as 35 billion barrels of OOIP of 10.5° API gravity and covers an area exceeding 100,000 ac. Well depths range from 6,000-10,000 ft (TVD) with some measured depths as high as 16,000 ft. 2013 average production exceeds 100,000 BOPD with a cumulative of 1.5 BBO or 4% of the OOIP (since the late 1940s). Approximately 900 wells have been drilled with 500 of them currently active. Early field development began utilizing 7-spot patterns with a well spacing of 1000m (214 ac/well). Subsequently, 577 m well spacing was utilized (71 ac/well). Venezuelan well spacing requires 600m for Eocene reservoirs so 577 m was acceptable allowing for optimum geometric well placement and uniformity. However, exact 577 m between wells could not be maintained due to surface limitations, multi-pad drilling and use of deviated completions.
The Venezuelan Ministry of Petroleum requested technical justification before providing drilling permits for any wells &lt;600 m which represented all current and future development. Optimal spacing was investigated to evaluate recovery effects while maintaining an average density of 71 ac/well. Analytical performance and static/dynamic modeling were utilized.
An analysis was conducted in four representative areas of the field with well spacing as low as ~400 m maintaining an average density of 71ac/well. Results indicated similar recoveries from wells ranging 400-600 m apart. A simulation model was utilized to validate the recovery as low as 50 m.
Actual performance results showed no interference if an individual well was at least 400 m from the next closest well. Reservoir simulation consistently showed no interference if at least 200 m was provided with a maintained average well density of 71 ac/well.
The technical analysis of well spacing and density was presented to the Venezuelan Ministry of Petroleum and it is expected to allow continued development in the Boscan field utilizing optimum drilling and completion strategies maintaining 71 ac/well. Well spacing exceptions as low as 200 m will also allow for increased recovery by utilizing more highly deviated wells, reducing drilling cost and allowing for new drilling opportunities.
Full-Field Dynamic Reservoir Characterization to Directly Impact Field Development Decision of a Cretaceous Age Naturally Fractured Reservoir in Mexico
Authors: Rojas-Figueroa Antonio , Pérez-Martínez Ernesto , Rivera-Zumaya Juan Jesús , Chen Chih-Ying , Jiang Yuanlin 
Published: June 2014

Abstract
Bacab field is located offshore in the Bay of Campeche approximately 100 km north of Ciudad del Carmen, Campeche, Mexico. The main producing reservoir in the field is the BKS reservoir, a Cretaceous age naturally-fractured reservoir with aquifer support. Most producers were completed near the formation top to avoid water encroachment through channeling or coning, however several producers had early water breakthrough, which impacts well performance and shortens well life. Pressure transient tests and production data were analyzed to identify various flow regimes present in Bacab wells. It was done to explain the early water breakthrough, determine appropriate operating conditions to control water production in wells near faulted areas, and better design future field development strategy. Using static reservoir characterization and dynamic reservoir simulation, we iterated and validated these elements to match the history of the wells.
Numerical simulation results and pressure transient analysis (PTA) from a BKS well completed around the fault indicated the fault is conductive, which explains that the well's rapid water production was caused by water channeling through the fault. On the other hand, PTA results from several other wells suggested a constant pressure boundary, validated by the fact that the reservoir pressure drop is insignificant throughout the entire production history (approximately 22 years). This confirmed the primary reservoir drive mechanism in BKS is a strong aquifer drive. The strong energy could be beneficial to oil production or could be risky in channeling water to producers. Therefore, it is crucial to characterize the aquifer and reservoir vertical connectivity to enhance the field development plan.
Through integrated dynamic characterization, we successfully identified and validated several important reservoir features impacting well performance. These include reservoir dynamic properties in the vicinity of wells and faults, degree of reservoir connectivity, flow boundaries and the presence of a strong aquifer. With these inputs, we were able to successfully model the wells and reservoir and optimize BKS future exploitation designs. Furthermore, we established guidance of operating wells near conductive faults to maximize the oil recovery. An enhanced BKS field development plan based on this study is being implemented that includes well interventions and sidetracking. Accompanying reservoir management best practices in mitigating water coning and channeling while optimizing well production rates, preliminary results are promising.
Improvements to Data Acquisition and Bottomhole Fluid Sampling in Offshore Drill-Stem Testing
Authors: Engel D. , Azevedo V. , Pontes T. 
Published: June 2014

Abstract
Drill-stem testing (DST) is a proven method for reservoir characterization, which is important when designing well completion, future development strategies, and stimulation needs. If the completion designer has the ability to acquire accurate knowledge of fluid behavior as the hydrocarbon is produced to surface, decisions concerningcompletion strategies and expectations during well life can be greatly facilitated. The capability to collect a single-phase sample also is critical to reservoir modeling, as is achieving correct analysis of collected reservoir fluidswith accurate data collection frombottomhole gauges.
Samples must remain as single-phase fluid samples during recovery, and introducing high-pressure nitrogen behind the sample helps maintain sample pressure. By monitoring nitrogen-charge pressure in the sampler carrier, the exact time the samplers are fired is known. Thus, monitoring gauges will show any abnormality such as whether the annulus was pressurized or if the samplers were fired at an unwanted moment.
By integrating the sampler carrier gauge with a wireless acoustic data-acquisition system, status and confirmation of success of the trigger device are provided. Also, casing-pressure limitations are reduced by actuating downhole tools using acoustic telemetry instead of annulus pressure.
This paper discusses offshore field operations in Brazil to illustrate the importance of correlating gauge data from sample well fluids with a wireless acoustic telemetry system, and also, how the successful application of a wirelessly controlled DST work string composed of a data-acquisition system, an acoustically controlled tester valve, and samplers can significantly improve well-testing strategies.
Evaluation of Strategies for Enhancing Production of Low-Viscosity Liquids From Tight/Shale Reservoirs
Authors: Moridis George J , Blasingame Thomas Alwin 
Published: June 2014

Production of low-viscosity liquids (including condensates) from tight reservoirs (such as shales) is severely restricted by the ultra low-permeability of such formations, limiting production to a very small fraction (usually less than 5 percent) of the liquids-in-place. In this study, which is part of a wider investigation, we evaluate by means of numerical simulation several possible strategies to enhance low-viscosity liquids production from such reservoirs. These strategies include (a) physical displacement processes, (b) non-thermal processes to reduce the viscosity and the critical saturation of the liquids, (c) thermal processes, (d) enhanced reservoir stimulation, (e) novel well configurations and (f) combinations thereof. The objectives of this effort are to (1) to remove from further consideration potential production strategies that hold limited (if any) promise, and (2) to identify production strategies that appear to have potential for further study and development.
We first determine the baseline production performance of such reservoirs corresponding to several reference production regimes that involve minimal or no reservoir stimulation, standard displacement fluids (H2O or CH4), standard well configurations and no thermal treatment. We then evaluate the efficiency of several production strategies: (a) traditional continuous gas flooding using parallel horizontal wells and using the currently abundant shale gas, (b) water-alternating-gas (WAG) flooding, (c) huff-and-puff injection/production strategies using lean gas/rich gas in a traditional (single) horizontal well with multiple fractures, (d) flooding using appropriate gases (e.g., CO2, N2, CH4) using appropriate well configurations (mainly horizontal), with the viscosity reduction resulting from the gas dissolution into the liquids, and (e) thermal processes, in which the viscosity reduction is achieved by heating, possibly to the point of liquid vaporization and transport through the matrix to the production wells as a gas. Our study includes an analysis of the sensitivity of the liquids production to the main parameters defining each of the strategies listed above in an effort to determine the critically important parameters and factors that control the production performance and efficiency.
Experimental Investigations of the Effect of the Pore Pressure on the MSE and Drilling Strength of a PDC Bit
Authors: Akbari B. , Miska S. , Yu M. , Ozbayoglu M. 
Published: June 2014

Abstract
Experiments to investigate the effect of the pore pressure on a single PDC cutter forces were performed on Sandstone core samples. The experiments were performed in a high pressure single PDC cutter testing facility which is designed to perform one round of cut on the rock sample with a single PDC cutter. The cell confining pressure and the pore pressure were controlled and other operating conditions such as the depth of the cut and rotary speed were kept relatively constant.
The results can be applied to equip PDC bit simulators with better bit performance prediction by considering the effect of the formation pore pressure in the model. Such knowledge improves the drilling optimization analysis by providing more accurate predictive guidelines. The methods used and the lessons learned in these experimental investigations can be modified and utilized in more advanced similar types of investigations.
These experimental data were used in production of well-fitting correlations of logarithmic nature relating the MSE to the differential pressure and the confining pressure. The correlation demonstrates that the pore pressure has the same type of effect that the confining pressure has on the MSE but weakend by a coefficient. The same type of behavior, but to an even lower extent, was observed when the drilling strength was considered. Two rock and operational parameters dependent constants exist in the correlation; a detailed discussion on the physical meaning and methods to obtain those constants is included.
This study adds up to the rock mechanics knowledge of the PDC bit cutting action by proposing a quantitative means to account for the effect of the pore pressure. The results can not only be used to enhance the accuracy of any type of PDC bit simulator; but also, to test or validate rock failure models that consider the pore pressure.