bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Analysis of the Performance of Gravel Packs and Slotted Liners in Heavy Oil Operations
Authors: Akhimiona Nosa , Gorham Timothy , Auffant Ariel , Harrelson Jonathan 
Published: July 2010

Abstract
As hydrocarbon prices continue to fluctuate, it is imperative for engineers to come-up with optimum and cost effective ways of managing and developing a field. This is especially true in heavy oil operations, where the margins are very small. So it is pertinent to gain a better and broader understanding on how completion techniques can be optimized to gain the maximum value for companies.
This work presents an analysis/evaluation of gravel packs and slotted liners in a heavy oil field in California. The objective of this work is to compare gravel packs and slotted liners from a production and sand control standpoint. This work also has a secondary objective of re-evaluating the performance of old gravel pack wells that have been sidetracked using slotted liners.
The result of this work indicates that there is not a "one size fits all" solution to the problem of sanding in the field. So, it is imperative that all feasible completion techniques be analyzed and their impact on production and economics be considered. The conclusions and recommendations from this study will provide an insight through which Petroleum Engineers in heavy oil operations will make educated decisions on how to optimally complete a field and also obtain the most value for the investment.
Managed Pressure Drilling Micro Flux Technology Allows Safer Drilling in Highly Sour Reservoirs
Authors: Yang Guo Chun , Zhang Hong Jie , Epp James , Nas Steve 
Published: July 2010

Abstract
The developments in advanced managed pressure drilling technologies offers significantly improved safety aspects when drilling highly sour reservoirs. Drilling with a closed well bore system allows enhanced kick detection systems to be deployed on deep sour wells. Kick detection systems capable of detecting and automatically controlling a 2 bbl influx significantly increases the safety aspects of drilling highly sour reservoirs.
With these modern MPD systems it now possible to drill wells with the minimum overbalanced, which increases penetration rates in the sour reservoirs. Less drilling time and fewer trips enhance the safety aspects of sour operations. Drilling with closed systems that allow advanced and automatic kick detection systems further enhances the safety aspects of drilling sour wells. Combining these MPD systems with the vast underbalanced drilling experience gained in drilling highly sour reservoirs in Canada and North America allows small kicks to be safely handled.
This paper provides an overview of the new MPD systems and the kick detection capabilities. The paper then discusses the equipment up that can now be deployed to deal with any sour gas encountered during the drilling operations. This paper highlights the potential use of these MPD techniques for the sour gas developments in Central and Western China.
Subsurface Integration Leading to Improved History Matching: Case Study Using Malaysian Heterogeneous Carbonate Gas Field
Authors: Arsat Ahmad Hassan , Masoudi Rahim , Darman Nasir B. , Long Liew Wei , Othman Mohamad 
Published: July 2010

Abstract
It is well known that some of the carbonate fields in Central Luconia Gas Province, Sarawak, Malaysia, are subjected to severe geological heterogeneities and aquifer behavior. These are not usually well understood and captured during the initial field development study. This could potentially result in unreliable estimation of the hydrocarbon in place and estimated recovery factor as well as selected depletion and production strategies.
The studied field in this work, which is located in Central Luconia area, is believed to have a common strong aquifer with the neighboring fields and is a highly heterogeneous reservoir. The field has numbers of extensive and localized baffles/barriers together with high intensity of karstified areas, resulting in significant variations of reservoir characterization and hence dramatically affects the flow behavior in the reservoir, well productivity, water break-through and high abandonment pressure. Due to these heterogeneities, reliable prediction and control of the waterfront and movement, as well as the optimized production policy have significant impact to the hydrocarbon ultimate recovery from the field.
This paper presents the adopted methodology and results of the integrated study done on this complex reservoir to monitor waterfront and contact movement by incorporating the effect of the karst areas and tight zones into the field dynamic model to improve the predictability of the final history matched model. The karst areas were mapped out from the available semblance maps and the permeability of those areas were re-evaluated accordingly. The field experienced various pressure patterns and there are several pressure drifts due to the different pressure depletion pattern through the tight zones. This complex pressure patterns have been used as a guideline in incorporating the karst areas and representative tight zones in the model.
By applying this methodology, the resulting history matched model showed significant improvements and demonstrated a more representative tool in monitoring and optimizing waterfront and movement in the reservoir. Based on this study, the recovery factor of the field can also be improved by 11%.
Accurate Simulation of Non-Darcy Flow in Stimulated Fractured Shale Reservoirs
Authors: Rubin Barry 
Published: July 2010

Abstract
Unconventional shale gas reservoirs require stimulation via hydraulic fracturing of pre-existing fracture networks for practical exploitation, creating a stimulated reservoir volume (SRV). Within the SRV, gas flow from the nano-Darcy shale to the complex stimulated fracture network has been modeled in reservoir simulators using a variety of techniques which upscale/simplify the fracture network. The simulation techniques used in the past were normally not compared with reference solutions.
This work investigates using finely-gridded single well reference solutions (approximately 6-14 million cells) for simulating Darcy and non-Darcy flow within an explicitly modeled SRV complex fracture network, in 2-D, with and without primary hydraulic fractures, as well as scenarios which model stress sensitive permeability and later re-stimulation of a horizontal well. The network fractures use cells which are only 0.001 ft. wide.
The reference solutions are compared with standard dual permeability and MINC (multiple interacting continua) dual continua models as well as novel models which simulate flow inside of the SRV using coarse, logarithmically spaced, locally refined, dual permeability grids, and simulate flow outside of the SRV using unrefined dual permeability grids. These coarse models can be run in minutes on standard hardware, where as the reference models can take days to run on the same hardware.
We will show that excellent matches to the reference solutions are possible using a modest number of refinements to simulate the flow within the SRV when the fracture permeability and the fracture Forchheimer number (for non-Darcy flow) are scaled as described in the paper. These techniques allow the use of 2.0 ft. wide fracture conduits to mimic non-Darcy flow in 0.001 ft. wide fractures.
Good agreement between the reference and coarse models are observed even during the early flow period of the reservoir.
An Improved Laboratory Method to Estimate Flow Initiation Pressures and Near Wellbore Return Permeabilities
Authors: Suri Ajay , Sharma Mukul M. 
Published: July 2010

Abstract
The flow initiation pressure (FIP) is defined as the drawdown required to initiate flow when the well is put on production. The standard laboratory method used to measure FIP uses a constant flowback rate. However, as shown in this paper, this method results in a large overestimation of the FIP. Instead an improved flowback method that uses a series of constant differential pressures is shown to more accurately measure the FIP. This improved method closely mimics a constant drawdown applied in the production well. In addition, the method measures the return permeability during flowback as a function of the differential pressure (drawdown).
Two types of drilling fluids (sized calcium carbonate and bentonite) are used on sandstones and carbonates with a wide range of permeability from 4 to 1500 md. Both single-phase (only brine) and two-phase (brine and oil) experiments are conducted in lab-simulated open-hole and perforated completions to measure the FIP and the return permeability spectra.
Small values for FIP are found in all the experiments (considerably smaller than presented in the literature and measured with a constant flowback rate). The small values of FIP suggest that the pressure gradients in the field should be sufficient to initiate production in most wells.
It is shown that both the FIP and the return permeability are controlled by the internal filter cake and are not related to the removal of the external cake. However the mechanical properties of the external cake (which are related to the properties of the internal cake) can be used to estimate the FIP. The experiments suggest that for the drilling fluids used in this study a pressure drawdown of 120 psi/ft during production is needed to ensure a skin factor that is less than 1 in open-hole completions.
Development of Petrophysical Stress Models For Conversion of Core Porosity and Permeability Data from Ambient to Reservoir Conditions - A New Hybrid Approach
Authors: Williams Steve O. , Batarseh Samih S. , Solanki Max 
Published: July 2010

Abstract
Correction of ambient measured core data to reservoir conditions poses a major challenge in the optimal use of historical core data in reservoir description and exploitation. The use of such data in any form of reservoir evaluation without appropriate correction to reservoir conditions will result to some degree of uncertainty in reserves determination and flow performance predictions.
Core data from the Ventura Avenue field, California was used for this development. This field is structurally complex and consists of a turbidite sand sequence that is thick, shaly and thinly bedded. Porosity and permeability values are low and variable. This paper presents a new hybrid approach that uses the numerical or error minimization techniques to approximate the non-linear and double exponential relationship of porosity and permeability versus stress and takes into account the shaly and laminated sand variability, the existence of microscopic pore throat attributes and resultant stress patterns inherent in the Ventura core data. This approach eliminates the use of average parameters that are more favoured in homogenous reservoirs. It also examines and compares with other existing methodologies in the industry. The result is promising and shows a more improved and accurate porosity and permeability conversion model that can be used in both clastic homogenous and non-homogenous reservoirs.
Drillpipe Conveyed Logging Provides Solutions for Pressurized Mud Cap Drilling Operations
Authors: Toralde Julmar Shaun , Fisher Kevin M. , Collecott David J. , Stewart John C. 
Published: July 2010

Abstract
The variant of managed pressure drilling (MPD) used in oil and gas wells that experience severe to total circulation losses accompanied by the persistent influx of reservoir fluids is called pressurized mud cap drilling (PMCD). In this method, the well is closed in on a rotating control device (RCD) and a light annular fluid column or mud cap is maintained in the annulus. Sacrificial drilling fluid, mostly water, is pumped through the drillpipe and together with the cuttings, are swept into the loss zones. No returns reach the surface.
Once target depth is reached using the PMCD process, subsequent operations, logging in particular, need to interface with PMCD equipment and methods in order for them to take place. However, the continued presence of severe losses and the possibility of kicks make it difficult to employ conventional wireline logging methods in wells drilled using PMCD. The requirements and difficulties of logging in PMCD mode most of the time lead to the scrapping of the logging program.
This paper presents the answer to the challenge of logging safely, efficiently and successfully in PMCD mode by utilizing a commercially proven compact drillpipe-conveyed logging system known as the well shuttle, in conjunction with a downhole isolation valve (DIV) and the RCD. It provides the set-up of the proposed system and discusses its capabilities and limitations. The advantages and disadvantages of the system, as well as how it compares to wireline logging methods in PMCD operations, are also discussed.
Running Liners and Well Completion in Pressurized Mud Cap Drilling Mode in Indonesia
Authors: Toralde Julmar Shaun , Hillis Keith 
Published: July 2010

Abstract
Catastrophic losses accompanied by reservoir fluid influx that are commonly experienced when drilling oil and gas wells through fractured and vugular carbonates in Indonesia were solved using a managed pressure drilling (MPD) variant called pressurized mud cap drilling (PMCD) to drill through the loss zones and reach target depth (TD) with minimal non-productive time. The well is closed in on a rotating control device (RCD) and a light annular fluid column or mud cap is maintained in the annulus, while sacrificial drilling fluid, mostly water, is pumped through the drillpipe and together with the cuttings, are swept into the loss zones. The method has been largely successful in allowing adopters to reach TD, but difficulties as to how the liner and well completion can be run in PMCD mode have been encountered. The requirements of completing the well in PMCD mode most of the time leads to countless failed attempts to kill the well or circulate a mud weight that is at balance with formation pressure.
Recent PMCD operations, however, have provided success stories as to liner and well completion running, both in the onshore and offshore setting in Indonesia. These successes have largely been brought about by appropriate liner / completion system design and by the adoption of new techniques that complement the procedures involved in operating in PMCD mode. These methods have allowed for the proper management of pressures while running liner / completion with total losses and have subsequently allowed the containment of the same. The details of these methods employed for running liners and well completion safely, efficiently and successfully in PMCD mode in onshore and offshore locations in Indonesia are provided in this paper, as well its capabilities and limitations. The set-up of the liner and completion equipment that have been run in PMCD mode along with recommendations for improvement are also discussed.
Increasing Ultimate Oil Recovery by Infill Drilling and Converting Weak Production Wells to Injection Wells Using Streamline Simulation
Authors: Sayyafzadeh M. , Pourafshary P. , Rashidi F. 
Published: July 2010

Abstract
Developing a giant field is a challenging task; the main goal is to reach to the highest ultimate oil recovery (UOR) by finding the best locations for new producers and injectors. Besides, converting existing producers to injectors and vice versa are other ways to increase the recovery. Hence, in this approach, we use combination of infill drilling and converting producer well to injector so as to maximize UOR.
Lots of methods are recommended to develop fields, but none of them is comprehensive enough. To develop a field, the location of a new well should be considered and then its effect on the ultimate production should be investigated. This approach normally deals with testing hundreds or thousands of potential infill alternatives by numerical simulations which is a very time consuming and expensive process.
One of the newest methods to develop a field is using streamline simulation. In this approach, we suggest two main stages; first to gain the most possible advantages from the infill drilling, new producers should be drilled in sections of the reservoir where the streamline density is low and the oil saturation is high. Second, converting mostly dead producers to injectors could be a very useful method based on the density of the streamlines around the old producers. We used the method to develop a complicated reservoir. For this reason, we used grid-base and streamline simulation to verify the outcomes. The results show that UOR increases around 70 percent by infilling and switching the producers to injectors.
In this work, we use the streamline approach to develop a guideline to drill new producers and switch some of the old producer wells to injectors in order to increase the oil recovery. This method could compete favorably with EOR processes on a recovery basis for much less investment and operating cost.
Maximizing Production Life With the Use of Nanotechnology to Prevent Fines Migration
Authors: Belcher Christopher , Seth Kushal , Hollier Ron , Paternostro Barney 
Published: July 2010

Abstract
Sand-producing reservoirs sometimes contain particles that are small enough to pass through the regular sand control media such as proppant and screens. The tiny particles, referred to as fines, are produced into the near-wellbore region where they can cause plugging of proppant packs and perforations that can severely decline production. These formation fines can cause major erosion of screens and can plug surface equipment, and are very expensive to dispose of. As a result, many solutions have been presented in an attempt to prevent fines from being produced. These solutions range from resin applications to formation consolidation treatments, which have proven to be expensive and which most often fail to achieve their purpose. In order to approach the problem from a different perspective, nanoparticle technology was applied in conjunction with hydraulic fracturing to combat the fines migration issue.
The particular case in this paper is focused on the Gulf of Mexico; however, the technology can be applied to any reservoir in the world where formation fines affect the production life of a well. The use of nanotechnology in a hydraulic fracture allowed the operator to achieve near-initial production rate without producing fines particles. The postponement of fines entering the near-wellbore region will also protect the investments made in the downhole assembly and fracture as well as surface equipment, while extending the production life of the well and minimizing the frequency of intervention.
Successful Extended Reach Approach in Production Logging Applications
Authors: Kady Alaa , Al-Ghafly Abdulhadi A. , Al-Khalifah Hamazah A. , Green Todd , Ramsey Tim , Pascal Monis , Smith Steve 
Published: July 2010

Abstract
The increasing demand for horizontal production logs is driving the use of all possible well-intervention technology approaches to fulfill technical diagnostic requirements and to acquire maximum logging coverage. Maximizing coverage will result in managing and exploiting the reservoir more efficiently.
Coiled tubing (CT) is commonly used as an intervention tool for long openhole horizontal logging. As with any intervention tool, however, CT has operational limitations. Depending on the diameter of the openhole sections and the well trajectory, accessing laterals greater than 5,000 ft (1,524 m) is often problematic or not possible due to helical friction lock-up. Conventionally, we could change the geometry of the intervention (CT OD), utilize lubricants (metal/metal friction reducers) and more recently, use downhole tractors (well completion ID’s/OH OD’s might prevent some applications). The use of large–OD CT strings and lubricants have yielded 5-10% incremental reach in some cases. This paper highlights an alternative approach to enable the CT logging operation to access the entire openhole lateral.
Incorporating a downhole vibrating tool to the coiled tubing bottomhole assembly significantly extended lateral reach capabilities of recent coiled tubing logging well interventions. As a result, previously inaccessible openhole lateral sections not reached by conventional coiled tubing methods, utilizing lubricants and/or larger OD CT, have now been accessed and successfully logged.
The use of the vibrating tool as part of the logging BHA on the coiled tubing resulted in decreased friction and weight stacking, allowing the coiled tubing to run in the hole far beyond previous lock-up points.
This paper discusses two cases where production logs were completed on two onshore, openhole horizontal power water injection wells in the South Ghawar Field for Saudi Aramco Company. Each of the two wells were first attempted without the aid of a vibration tool, and as per the pre-job computer simulation total depth could not be reached due to predicted lock-up (helical buckling). The wells were then reentered with the vibrating tool, allowing the CT to reach at least 20 percent further into the openhole lateral than the previously modeled lock-up, thus allowing the unreached section to be logged.
Novel Approach in the Development of Next-generation Numerical Reservoir Simulator
Authors: Liu Wei , Li Zhiping , Han Dakuang , Jiang Hanqiao 
Published: July 2010

Abstract
Development of optimal depletion strategies for hydrocarbon reservoirs remains a top priority for petroleum companies in their asset management. There is a clear need for technologies that enable engineers to realize the synergy across a spectrum of reservoir management processes and subsequent establish optimal operation strategies in a fully integrated fashion. Considering the fact that a typically oil and gas production system involves multiple dynamics at different scales, effective representation and modeling of the system has been one of the greatest challenges facing the industry. In conventional approaches, furthermore, the computational intensity associated with the optimization of an integrated system (e.g. unified subsurface reservoirs, wells, and surface facilities) is either beyond current hardware capability or counteractive.
In this paper, a dynamic scaling formulation is proposed together with a nonlinear domain decomposition algorithm in order to address multiscale physics from reservoir geophysics and fluid flow at a very fundamental level. The proposed numerical scheme derives sets of dynamic scaling factors that provide a means by which the general conservations of mass, momentum and energy can be tailored and qualitatively ascertained at run time in accordance with the different physical phenomena and scales of objective domains, while the nonlinear domain decomposition technique provides an effective way to synthesize a multidomain problem into a desired global one. The methodology can be extended to simulate various systems of interest in hydrocarbon production processes, but this paper focuses only on subsurface reservoirs to accurately capture the effects of various scale fluid flow phenomena ranging from hydrocarbon components to statistical reservoir heterogeneities.