bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Emulator Methodology for Uncertainty Reduction Quantification
Authors: Ferreira C. , Vernon I. , Schiozer D. J. , Goldstein M.
Published: June 2014

In petroleum engineering, simulation models are used in the reservoir performance prediction and in the decision making process. These models are complex systems, typically characterized by a vast number of input parameters. Usually the physical state of the reservoir is highly uncertain, and thus the appropriate parameters of the input choices. The uncertainty analysis often proceeds by first calibrating the simulator against observed production history and then using the calibrated model to forecast future well production. Most models go through a series of iterations before being judged to give an adequate representation of the physical system. This can be a difficult task since the input space to be searched may be high dimensional, the collection of outputs to be matched may be very large, and each single evaluation may take a long time. As the uncertainty analysis is complex and time consuming; in this paper, a stochastic representation of the computer model was constructed, called an emulator, to quantify the reduction in the parameter input space due to production data over different production periods. The emulator methodology used represents a powerful and general tool in the analysis of complex physical models such as reservoir simulators. Such emulation techniques have been successfully applied across a large number of scientific disciplines. The emulator methodology was applied to evaluate the production data capacity to identify uncertain reservoir physical features over the production period for a synthetic reservoir simulation model. The synthetic model was built to represent a region of an injector and related producers. In the case studied; thousands of realizations were required to identify certain physical reservoir features. This justifies the use of emulation and shows the importance of this technique for the identification of regions of feasible input parameters. Moreover, the impact on the input space reduction due to different production periods was determined. The emulator methodology used assists in carrying out tasks that require computationally expensive objective function evaluation, such as identifying regions of feasible input parameters; making predictions for future behavior of the physical system and investigating the reservoir behavior.
Effect of Dissolved Solids on Reuse of Produced Water in Hydraulic Fracturing Jobs
Authors: Haghshenas A. , Nasr-El-Din H. A.
Published: June 2014

Multiple-stage hydraulic fracturing jobs are usually needed to produce economically from tight sand gas reservoirs. High costs of water acquisition and waste water disposal, and the lack of available water resources near operation sites, make the reuse of produced water an unavoidable option. Applications of produced water in hydraulic fracturing jobs result in low quality fracturing fluids, which usually have high levels of hardness and salinity. This is especially true for flowback fluids, which contain high polymer loading. The viscosity and rheological properties of fracturing fluid, significantly affect leak-off rate, proppant placement, length and width of fractures, fracture conductivity, and consequently, the success of the treatment. The objective of this study is to determine the acceptable dissolved solid contents for flowback fluids to prepare fracturing fluids.

Analyses of 36 flowback fluid samples from the West Texas region have been collected, and experimental studies were conducted on the analysis of the dissolved solid contents of produced water, which affect the application of flowback fluids and the capability of prepared fluids in proppant transport and handling. A high-pH borate crosslinked guar-based polymer has been picked to determine the ranges of acceptable salt contents. Dynamic viscosity and rheology tests, static proppant settling, and small-amplitude oscillation rheology, were the methods used to evaluate prepared samples at room temperature and medium temperature (225°F).

The results show that some divalent cations such as calcium and magnesium have severe negative effects on the prepared polymers. Calcium is the controlling ion and about 60% of flowback fluids need to be treated to meet the maximum acceptable concentration criteria for these ions. Although monovalent cations such as sodium and potassium were tolerable at higher concentrations and the potassium contents in almost all flowback fluids meet the determined acceptable value, more than 70% of samples need to be treated for high sodium ion concentration. Although the presence of other ions like iron, show no significant variation in fracturing fluid properties, they can affect treatment jobs in special cases. The results comply with the extracted outcomes in SPE 168614 and show that adjusting the concentration of the polymer, buffer, and crosslinker can minimize the effect of temperature and salts. The fluids prepared with the determined ranges of dissolved solids showed reasonable rheological stability and proppant transport characteristics. This paper introduces the practical operating range for produced water content and defines the factors that can adversely impact borate-crosslinked fracturing fluid characteristics at low and medium temperature applications.
Unlocking the Potential of Mexican Offshore Fields through Real-Time Optimized Placement of Carbonate Acidizing Treatments
Authors: Inda Lopez A. , Inda Herrera L. A. , Soto Lopez E. O. , Ramondenc P. , Murillo Vallejo A. L. , Rosado Rivero I. , Worden S.
Published: June 2014

Mexico has long based its strength on the exploitation of its offshore fields to become one of the largest oil producers in the world. Although still yielding most of its production today, those mature fields have entered a downward trend for the past few years, with a gradual decline of their hydrocarbon output. This trend coincided with an increase in work over operations, most of them involving matrix acidizing interventions in carbonate formations for damage removal and stimulation purposes.

Matrix stimulation of offshore Mexico fields presents several challenges, starting with the very nature of the carbonate rocks composing the reservoirs, whose properties can greatly vary within a short distance. In addition, the well conditions are also at times not well understood, with perforated intervals heterogeneously producing, and the increasing occurrence of water production. Finally, due to the location offshore, time-efficiency and operational simplicity became important workover requirements that have a direct impact on the chosen stimulation procedure, often achieved using a simple bullheading sequence, which unfortunately leaves the much needed control of zonal coverage out of the equation.

This paper presents a carbonate acidizing workflow and interpretation method that have been developed and successfully implemented in offshore Mexico over the past couple of years. This technique constitutes the cornerstone to assessing and controlling matrix acidizing treatment coverage while it is pumped, in real-time, to ensure optimum treatment performance and maximum return on costs. The workflow relies on the use of a fiber-optic line enclosed inside a coiled tubing (CT) string to acquire distributed temperature sensing data, which are analyzed and translated into a zonal coverage profile using a fast interpretation algorithm. This information then allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence.

As the case studies presented in this study will show, there is a lot to gain from this improved methodology. In particular, they show that the long-standing blind bullheading practice results in some shortcomings that may be detrimental to truly unlocking the full potential of those offshore fields.
Application of Elastomer More Resistant to Gas in Progressive Cavity Pumps in Boscan Field to Improve Run Life
Authors: Marchan L. , Socorro D. , Concalves E.
Published: June 2014

The Boscán Field, a giant heavy oil field located on land 45 km SW of Maracaibo, Venezuela, was discovered in 1947. It has been operated by a joint venture company called Petroboscan since 2006. It covers an area of approximately 660 km2 with 890 drilled wells and 426 active wells with 10.5 API oil. Since 2001, Progressive Cavity Pumps (PCP's) have proven to be a viable, cost-effective means of production in the Boscan Field. It contributes 23% of the total field production through 134 active PCP wells. PCP systems are the second artificial lift method most used in Boscan field, and include both insert and tubular PCPs. From the beginning of the project, two types of elastomer compounds (NBRA & HNBR) were selected and successfully applied for several years. However, the reservoir pressures in some areas of the field have declined significantly, generating higher GORs, which have resulted in the reduction of PCP run life.

A new challenge was established to improve pump run life by changing the elastomer composition to be more resistant to explosive decompression during well shut-in events. A total of 13 wells with repetitive pump failures due to gas were selected. Crude samples were taken and elastomer compatibility tests were performed. The following step consisted of installing and testing the elastomer in candidate wells. Elastomer #1 was installed in two different wells and showed an improvement in run life from an average of 83 days up to 500 days. Improvement of the run life with elastomer #2 was also significant, from an average run life of 162 days up to 345 days. Based on this experience, the elastomer # 2 was considered to be the most optimal to be used in the field and has been installed on 8 wells with a current run life of 368 days.

This paper will contain the details of the field trial of gas resistant elastomer, and the optimization philosophy used in Boscan, to improve PCP run life in high GOR environments.
Conceptual Study and Evaluation of the DTS-Fiber-Optic System as Monitoring System of Injection-Production Profiles in Conventional Reservoirs: A Colombian Field Application
Authors: Jaimes M. G. , Prada J. A. , Dorado R. , Cornejo E.
Published: June 2014

About 70% of the oil produced today comes from mature fields, which focuses the interest of the industry on these fields, especially when the recovery factor is low (under 30%).

To increase the recovery factor, techniques as water injection can be implemented which also helps to mitigate the environment impact, transforming the water produced from an unwanted to a resource.

Having permanent control over the reservoir when is going through a secondary recovery, requires optimize the processes of displacement and recovery. The monitoring has the power to set the behavior of operational parameters for the optimization of the injection-production operations and to diagnose potential problems, which allow having a specific and a general vision of the process.

The continous monitoring process should be considered from the planning of injection-production system. The technology that provides constant monitoring is the DTS-Fiber Optics System, which allows the generation in real-time of production profiles and come across with more frequently the injection distribution. With the proper interpretation of these logs the following can be achieved: the injection rate optimization, injectivity leak detection, leak control in wells, cross-flow detection, the contribution of each zone in a stratified reservoir, and detection of the water breakthrough in the producer well.

This paper contains a conceptual level study, which presents the working principle, applications worldwide, Benchmarking, benefits, advantages, best technical setup and the correct procedure for implementing the DTS-Fiber Optic system for both a producer and an injector well. Additionally an economic evaluation which compares the DTS-Fiber optic System with conventional monitoring systems currently implemented to generate injection and production profiles in the Yariguí-Cantagallo field in Colombia are presented.

Finally, the main findings, conclusions and recommendations obtained in this study are shown.
Design and Validation of an Improved Shunt Tube System
Authors: Bonner A. , Hailey T. , Veit J.
Published: June 2014

Shunt tube technology to mitigate premature bridging in the annulus while pumping slurry has been used successfully in the oilfield for over two decades to assure complete gravel placement. The systems have been applied in a variety of scenarios including single and multizone completions, cased and openhole completions, and both gravel and frac-pac applications. By deploying a screen system empowered with the slurry bypass mechanisms of a shunt system, an operator usually experienced greater job reliability, a reduced possibility of pack failure, and maximized production.

This paper discusses an improved version of the traditional shunt tube system that has recently been developed by a major engineering and service company to enhance sand screens for gravel packing in long production intervals. The system was designed primarily for gravel packing in horizontal wells and is a system with two larger transport tubes and two smaller packing tubes, all mounted to standard sand screens in an eccentric design. A new seal design improves sealing capability between the joints of screen. By the optimization of the attachment of the tubes to each other, to the rings mounting the system to the screen, and to the sealing fittings at the transport tube ends, the design significantly enhances system capabilities.

Computer flow modeling was used to improve erosion resistance and lower pressure loss by reducing friction at tube connection flow transitions. Extensive test programs to ensure equipment integrity, including torque, tension, and compression capability of major components were used. The system can be assembled more quickly due to the shroud covering the joint connection being an integral component of the screen with no bulky clamshell hinges or pins to be assembled.

The improved pressure sealing, erosion resistance, ruggedness, improved rig assembly times, and system qualification will be presented in the paper.
A Method To Size Gas-Liquid Horizontal Separators Handling Nonstable Multiphase Streams
Authors: Hernandez-Martinez J. L. , Martinez-Ortiz V.
Published: June 2014

The sizing procedures of all the process equipment in oil and gas industry share a common assumption: the stream flowrate measured at the inlet is always constant or stable. This principle works fine for plants where the process conditions are controlled, but it does not apply to primary production facilities where the streams come from multiphase flowlines or wells. In a real horizontal gas-liquid separator, the inlet stream flowrate is not constant and the liquid fraction fluctuates as a function of time. This fact must be considered in the design procedure applied to these units.

The sizing procedure described here allows to size horizontal gas-liquid separators, considering non-stable flowrate at the inlet, or fluctuations in the liquid fraction on the same stream. The method looks for the best unit design to address these variations and also gets the smallest possible horizontal gas-liquid separator.

The proposed method consists of two parts. The first one is solved by a dynamic multiphase flow simulator which allows modeling the multiphase flow in the pipeline and predicting flowrate and liquid fraction fluctuations at the separator inlet. In the second part, the horizontal separator sizing is solved following a modified Svcek and Monnery (1993) method. It is adapted to take into account a non-stable stream at the inlet, using the surge volume calculated by dynamic multiphase simulation. Other well-known methods are also reviewed, such as Arnold (1986). Relationships between the Svcek and Monnery approach and other methods are depicted.

The method is illustrated sizing a gas-light oil separator located in an offshore production facility where the feed stream is identified as non-stable. This behavior is taken into account, and the effect in the vessel volume is numerically evaluated. This approach allows obtaining the smallest separator volume based on dynamic simulation results; as compared to the sizing based on overdesign rules.

The approach depicted here can be applied for sizing horizontal gas-liquid separators in which the dynamic nature of the multiphase flow must be taken into account and the smallest possible volume is desired.
An Analytical Model Coupled With Data Analytics to Estimate PDC Bit Wear
Authors: Liu Z. , Marland C. , Li D. , Samuel R.
Published: June 2014

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

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

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

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

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

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

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 <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

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

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

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.
Alkali Metal Silicides: A New Material for Heavy Oil Production Processes
Authors: Krumrine Paul H. , Lefenfeld Michael , Romney Gregory A.
Published: June 2014

Alkali metal silicides are a new class of materials that can provide thermal, chemical and immiscible gas drive benefits in one treatment. Not previously known in oilfield applications, these materials are solid, energy-dense chemicals that generate heat, hydrogen and an alkali silicate upon reaction with reservoir water. The reaction is only limited by availability of any type of water; in a closed environment, pressures >10,000 psi can be generated. Alkali metal silicides are dispersible in various hydrocarbon fluids to facilitate placement in a reservoir and can be coated to allow time delayed reaction. The powders can also be milled to submicron size for optimum injectivity in high permeability reservoirs. This combination of material and reaction-product properties makes silicides particularly applicable for the recovery of heavier crude oils. Since the chemical reaction occurs in-situ, silicides are not subject to the thermal efficiency limitations of conventional thermal EOR processes at depth. Further, the resulting hydrogen and silicate reaction products represent a "green" chemistry approach that may reduce the environmental impact of oil recovery operations. This paper presents bench scale core flood results demonstrating that alkali metal silicides can recover greater than 50% of residual oil. Results also show that alkali metal silicides can provide accelerated oil production, as much as 20% faster than comparable chemical technologies.
Technical Implementation and Benefits of Use of Produced Water in Slickwater and Hybrid Treatments in the Bakken Central Basin
Authors: Griffin Larry , Poppel Ben , Siegel Joel , Weijers Leen
Published: June 2014

The Bakken boom in North Dakota has been well documented. From a development perspective, the majority of the acreage has been drilled with an initial well to hold the acreage and the emphasis has shifted to infill drilling. As the development progresses, the industry seeks to apply more sustainable practices which includes the recycling of produced water. A number of efforts are underway to consider the use of produced water for well stimulation, and the economics are expected to improve with infrastructure such as central gathering systems. From an economic and environmental point of view, reuse of produced water in the Williston Basin is a sustainable practice to conserve water and save on well completion cost.

A number of technical challenges accompany the application of produced water in well stimulation including stimulation design, execution, and effectiveness. Considerable attention is required regarding fluid chemistry including stimulation additives, guar-based gels, crosslinkers, and friction reducers (FRs) used in slickwater. For example, properties of friction reducers change considerably in the light of the high salinity of Bakken produced water. Effective friction reducers are critical for slickwater jobs that are pumped at high rates of 70 bpm and the early slickwater stages using in hybrid fracs (combination of gel and slickwater). Achieving that high rate is key to effectively divert fluid flow and maintain sufficient rate to transport proppant in a long lateral.

This paper provides insight into the effectiveness of using produced water into slickwater designs in the Bakken petroleum system. The work discusses screening of various experimental and commercial FRs to determine their individual effectiveness with fresh water and produced water. The efficiency of a few tested FRs is then measured in actual field treatments, and we conduct a comparison of the frictions measured in field and lab to provide a methodology for proper comparison of the two, enabling a reasonable forecast of frictions measured in the lab to pipe frictions expected under field conditions.
An Integrated Approach for Developing and Applying Multiple PVT Model Zones in Thermal Compositional Reservoir Simulation
Authors: Yang Zhengming , Urdaneta Alfredo
Published: June 2014

The South Belridge Opal-A diatomite reservoir is under waterflood and steamflood development. Laboratory measured compositional and viscosity data, API gravity distribution from commingled produced oil, as well as field production performance all suggest the existence of more than one oil type: light oil (29°API) and intermediate gravity oil (22°API), regionally separated by faulting. Accurate PVT and viscosity models are essential for use in thermal compositional reservoir simulation to quantify two major steam flood mechanisms: oil distillation and viscosity reduction. It is a challenge to develop PVT models with limited laboratory measurements of the initial, limited-interval, oil samples. Validation of legacy compositional measurements against mol-fraction distribution vs. SCN (Single Carbon Number) is critical for obtaining a meaningful PVT property model. A new approach of developing viscosity temperature relationship for each pseudo component based on PVT property modeling, and the use of the ASTM viscosity model with limited high temperature viscosity measurements is proposed. Integrated investigation of faulting from static geological modeling and API oil gravity measurements from commingled produced oil and sidewall core oil samples were used to define the boundary of two PVT regions. Waterflood and steam flood project responses were analyzed to assess the impact of fluid types (light or intermediate oil) on waterflood and steam flood performance. Field-scale reservoir simulation of both waterflood and steam flood processes demonstrate the success of applying the new approach for field-scale multiple PVT model zone studies.
Characterizing the Oil Reservoirs in the Uinta Basin
Authors: Merkel Richard , Lessenger Margaret
Published: June 2014

Oil reservoirs in the Uintah Basin are extremely complex and have to be considered in the ‘Unconventional’ category. This is partially because of the lacustrine depositional environment which resulted in numerous self-sourcing reservoirs that vary greatly in wettability and mineralogy (very clastic to very carbonate). Analysis of these reservoirs is compounded because of the low porosity/permeability, high paraffin content, and natural fracture distribution. Standard log analysis to determine OIP has proved problematic. As a result, a more unconventional logging suite to examine fluid distribution and properties is being employed.

This paper presents some of our findings in the understanding of the liquid hydrocarbon distribution. Only then are we able to determine efficient primary production techniques as well as flow characteristics for secondary water-flood projects. Because of the discontinuous nature of the reservoirs, we have found that some intervals are most economically produced with vertical wells while others are best produced with horizontals.

The viscosity of the oil is highly temperature dependent because of the high paraffin content. The viscosity is also dependent upon asphaltine content which is present in the ‘black’ wax oil component. Fortunately, with new NMR techniques and continuous logging, the in-situ viscosity of the oil can be estimated. The NMR log is also used to differentiate between solid hydrocarbon (kerogen) and the liquid component. Dielectric measurements provide us with a water volume estimate that is essentially independent of the water salinity. This is particularly valuable in the water-flood area of the reservoir to determine remaining oil and residual oil saturation.

Petrophysical results from the open-hole logging that are calibrated to core are used in combination with core flooding experiments to feed into reservoir models. Fluid flow characteristics in this complex environment are measured at in-situ conditions through proper petrophysical analysis of core and logs.