bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methods and Benefits of Knowledge Sharing in the Petroleum Industry
Authors: Shadravan A. , Amani M. , Molinari D. , Hugall J. N. 
Published: December 2010

Abstract
In the year 2030, global energy demand will be almost 35% higher than it was in 2010, led by a power hungry world population of almost 8 billion. This looming energy crisis must be tackled by forming stronger inter- and intra-company collaborations,to maximize their exploration and production. Knowledge sharing (KS) is essential in every sector of all societies; employed as the main tool for achieving progress. It is the necessary key to make these stronger partnerships, providing networking communities in which to share information for the good of the organization.
There are many ways in which an organization can use knowledge sharing as an effective tool for gaining success, such as: websites and forums; peer-reviewed journals; conferences; and educational programs. Benefits of knowledge sharing include: enhanced learning opportunities and intellectual stimulation for employees; increased company efficiency; advances in R&D and in particular with forums, the creation of a searchable archive of previously answered questions for future use.
Should all organizations decide to adopt these cost-effective techniques, they would not only increase their capital but also help to solve the global energy crisis with more effective R&D in exploration and production. Organizations that enable their employees to access and interact with their company's knowledgebase are more likely to succeed than those whose individuals have limited sharing opportunities. This paper investigates some knowledge sharing methods that could bring success to a company and scientific societies in the competitive petroleum industry environment.
Reducing Exploration and Appraisal Risk in Low Permeability Reservoirs Using Microseismic Fracture Mapping—Part 2
Authors: Cipolla C. , Mack M. , Maxwell S. 
Published: December 2010

AbstractThe exploration and appraisal of low-permeability or unconventional hydrocarbon resources is significantly different than conventional reservoirs; exploration is more like appraisal, requiring pilot programs to test commerciality of these plays prior to embarking upon large-scale development (Hall 2007; Stabell et al. 2007), including the effect of completion and stimulation optimization (Haskett and Brown 2005). One essential component of low-permeability reservoir development is hydraulic fracturing, which virtually all of these wells require. With the introduction of hydraulic fracture monitoring (HFM), we are now able to measure fracture geometry and complexity, which has led to major improvements in treatment designs, well completions, and field development strategies in North America. HFM applications were once focused on development and infill drilling, but they have recently shown significant value for exploration plays (primarily in gas shale). HFM measurements now allow operators to more efficiently evaluate the effectiveness of stimulation treatments and completion approaches in exploration and appraisal wells, reducing the number of wells required to assess the economic viability of low-permeability reservoirs.The application of HFM to exploration and appraisal programs outside North America could significantly accelerate the evaluation of low-permeability reservoirs, where selecting the appropriate hydraulic fracturing design and well completion strategy will be key to success. It could also accelerate the learning curve, which is essential to quickly reducing costs and improving well productivity and hydrocarbon recovery. This paper presents several case histories that illustrate the application of microseismic mapping to characterize hydraulic fracture growth and improve stimulation designs and completion strategies, and demonstrates that the limitations on well locations required to implement microseismic mapping do not significantly increase the cost of the appraisal program.
Subsidence Prediction and Casing Integrity With Respect to Pore-Pressure Depletion With 3-D Finite-Element Method
Authors: Shen Xinpu 
Published: December 2010

Abstract
Pore-pressure depletion arising from oil production can cause subsidence of overburden formations as well as casing failures. The reduction of casing failure in a field containing compactable reservoirs is particularly significant to the reduction of non-productive time. Casing integrity can be influenced by various factors, including formation loading and inner pressure applied to the casing. This paper focuses primarily on a numerical analysis of casing failure caused by the formation geostress load related to pore- pressure depletions. Three-dimensional (3-D) numerical analyses of formation subsidence and related casing failure of a deviated well in a field of offshore Brazil was performed. The calculations considered pore-pressure depletions in the area around a production well and of nearby wells. A fully-coupled hydro-mechanical model was adopted to simulate the porous flow that occurred simultaneously with matrix deformation. Submodeling technique was adopted to address the discrepancy between the scale of the oilfield and that of the casing section. A full-field scale was used to simulate seabed subsidence at a global level. Casing failure was calculated at a local level at the scale of 10 m. The subsidence contour at the field level was plotted as cross- sections of the areas under study for the total formation depth of 10 km. The key casing section along the entire trajectory length was selected by using the finite-element method (FEM). For a given three-year period of production, two submodels were selected, which correspond to the various key-casing sections selected. Plastic deformations of each key casing section with different maximum formation loadings for the two different pore-pressure depletions have been given out. The numerical results of seabed subsidence simulations closely correlate with the measured data from references. The casing failure analysis also matched the observed phenomena. The proposed numerical procedure provides an effective tool for casing integrity estimates and prediction of production-related subsidence.
Laboratory Investigation on Light Oil Air Injection
Authors: Dubey N. K. 
Published: December 2010

Abstract
The Thermal EOR processes are the best available technique for ultimate oil recovery for many oil fields. Generally, there are two categories of thermal methods employed in the field: In which heat is produced at surface (Hot fluid injection) &In which heat is created in the formation (ISC-In situ combustion).
By comparison, heat loss is not generally a limiting factor for In-Situ combustion method.
In this paper, we will discuss the Laboratory procedure involved for the recovery of oil & gas by using compressed air techniques on light oil through the Combustion tube chamber associated with stimulated reservoir temperature and pressure condition.
The difference in case of fuel requirement in air ISC and O2 ISC is 0.2 millions of btu and in terms of cost $ 0.4 per million btu. So efficiency for the O2 will be highest compare to other. Further combustion is divided into forward and reverses according to mode of operation. Combustion front approaches at a point in a porous media containing oil and gas and move from injector to production well via creating various zones. The chemical reactions associated with the LOAI (light oil air injection) process are numerous and occur over different temperature ranges. Results carried in the laboratory gives the idea of oxygen utilization was 91.08% and average peak temperature was 505.879°C. So Air injection in light oil is a new technique to improve the recovery from heterogeneous and water flooded reservoirs.
An Evaluation of the Impact of Reactive Perforating Charges on Acid Wormholing in Carbonates
Authors: Diaz N. J. , Bell M. R. , Hardesty J. T. , Hill A. D. , Nasr-El-Din H. A. 
Published: December 2010

Abstract
The introduction of reactive perforating systems has led to tremendous improvements in well stimulation and productivity. Reactive charges generate a secondary energy release in the perforation tunnel immediately after it is formed, breaking up and expelling debris to leave clean tunnels across the perforated interval, irrespective of formation properties.
Although Bartko et al. (2007) have shown that clean perforation tunnels facilitate the evolution of a single, deeper-penetrating wormhole, there are no reported applications of reactive shaped charges in carbonates prior to acid stimulation. The present study was instigated to evaluate the impact of reactive charges on acid wormholing in representative carbonate cores.
A set of oil-saturated cores have been perforated under simulated downhole conditions, using either a conventional or a reactive shaped charge of equal explosive load. After CT scanning to eliminate outlying perforations affected by rock property anomalies, the set of cores were subjected to identical acid injection treatments representative of typical carbonate reservoir stimulations. Time to breakthrough and effluent chemistry were both analyzed and recorded. Finally, post-stimulation CT scans were used to evaluate wormhole morphology.
The laboratory experiments showed that reactive charges provide cleaner perforation tunnels with higher injectivity, which is beneficial for any type of stimulation job. Higher injectivity tunnels help to propagate more dominant and straighter wormholes resulting in less acid to propagate a given distance. This technology has a significant potential when perforating tight formations or heterogeneous intervals, where obtaining clean tunnels with conventional perforators is most challenging. Further research work needs to be done to evaluate if the difference in acid volume to breakthrough observed in the experiments would have a major impact in the field.
Preliminary Assessment of Tambaredjo Heavy Oilfield Polymer Flooding Pilot Test
Authors: Manichand R. , Mogollón J. L. , Bergwijn S. , Graanoogst F. , Ramdajal R. 
Published: December 2010

AbstractThe literature screening criteria for polymer flooding established the maximum oil viscosity at 150 cP; however, oil price increases and technology improvements have encouraged pilot tests in heavy oilfields. This paper shows the results of an ongoing polymer flooding pilot test in an inverted 5-spot well pattern in an onshore field in Suriname. The reservoir is fluvial deltaic with 900 ft depth in the pilot area. The oil viscosity is 400 cP at 97°F.The objective of the pilot test is to demonstrate that the production rate and recovery factor can be increased economically to extend the productive life and profits of the oilfield. Polymer flooding began after laboratory, numerical simulation, and preliminary economical evaluations indicated its feasibility. The analysis of reservoir-related parameters showed that uncertainties in long-term injectivity, polymer stability, wells communication, and fluid fingering-channeling cause a high-risk index. Therefore, a detailed subsurface surveillance and monitoring program was prepared and implemented. This program was guided by way forward road maps that target injection, flooding performance, and production assessment, and are based on a "plan, do, check, and act" approach.To date, 0.22 pore volume (PV) of the well pattern has been injected. The bottomhole pressure (BHP) of the four producer wells has increased by 1.7 to 2.7 times, showing the communication with the injector well, hence, after production has been adjusted to maintain the BHP between 75 to 100 psi. The injectivity is greater than the value estimated for profitability. Polymer breakthrough occurred in two of the 5-spot wells after approximately one year of injection, as forecasted in the reservoir simulation. A slight increase in the pattern oil production and water-cut reduction has been observed. Therefore, incremental oil production is expected in the forthcoming months.
Rigorous Drilling Nonproductive-Time Determination and Elimination of Invisible Lost Time: Theory and Case Histories
Authors: Maidla Eric , Maidla William 
Published: December 2010

Abstract
This paper addresses the measuring techniques that involved data quality control and automatic drilling operations detections of routine drilling operations that are available today in modern drilling programs, and goes through examples of how implementation was carried out in the onshore area that drilled a series of similar wells. Measurement accuracy, training, and the development of new work processes were successfully implemented that led to major KPI (Key Performance Indicator) time savings between 31% and 43%.
You cannot improve what you don't measure. And in this case you cannot measure without a proper data quality control (QC) procedure in place.
Breaking Old Paradigms With the Use of High Performance Water Base Mud Systems
Authors: Rodríguez Sandra , Arenas Ricardo , Sierra Humberto , Montoya Carlos , Serrano Mario 
Published: December 2010

Abstract
Hundreds of wells have been drilled since the early 1900's at the Putumayo basin in southwest Colombia. ECOPETROL (NOC) used traditional mud systems: lignosulphonates, potassium chloride, and finally lime or gypsum mud systems, all of them designed to manage exposure to anhydrite, a common mineral in the drilled formations. The calcium contamination adversely affects mud system properties, resulting in hole instability and frequent stuck pipe events.
Because of these issues, the operator considered using oil base mud (OBM) in a very environmental sensitive area. The OBM would generate undesirable waste and there were uncertainties about its performance, since few wells in the area had been drilled with OBM and the results were not very successful. Therefore, for drilling operations on the ECOPETROL Sucumbíos No. 5 well, a completely new high performance water base mud (HPWBM) was proposed and accepted. The new chemistry eliminated the use of bentonite and included a new flocculation inhibition mechanism, as well as new and powerful polymers. The system demonstrated that calcium and anhydrite were not a problem any more and the well was drilled in record time. More importantly, to the operator was able to evaluate the productive formations by running electrical logs, an operation that was normally cancelled because of severe hole problems. Casings strings were set and cemented per the well program and the well was completed as planned.
This paper presents the design state of the HPWBM, its performance while drilling and charts and graphics comparing the changes against the historical values recorded in the area.
Field Application of a Rig Less Practical Method for Stimulation of Beam Pumping Wells
Authors: Jaimes M. G. 
Published: December 2010

Abstract
One of the main mechanisms of damage at the sand face in the Lisama oilfield (Santander-Colombia) is the organic precipitation, which causes blockages on the perforations and reduces the production of oil, significantly increasing the cost per produced barrel. To remove this damage and recover production levels, chemical treatments are applied in cycles of 14 months, which are selectively squeezed in the formation to a radius of approximately three feet, using workover rig, a set of packers and pumping equipment. The Mugrosa formation is quite depleted and in many cases, organic stimulation by conventional methods is uneconomical (170000-200000 U.S. $ / well).
A method of stimulation to be used in beam pumping wells without Workover equipment (the Rig represents over 70% of the cost of treatment), using the energy of gas (high GOR wells producing from Mugrosa formation), which could reduce costs and make economically viable stimulation treatments in depleted wells, was designed. Successful of a solvent treatment depends on the proper solvent selection and how it is going to be placed in the well.
This paper presents the development of the designed method and its application in the field in the well Lisama 91 located in the Middle Magdalena Basin in Colombia, where the oil production was increased from 30 to 60 BOPD and stimulation treatment costs were reduced by 75 %, in comparison with conventional methods.
Challenges and Solutions to Optimize the Operation of Heavy Oil Fields in Remote Environmentally Sensitive Wetland Areas
Authors: Dodson R. J. , Anthony E. , Schuitemaker A. 
Published: December 2010

Abstract
Heavy oil (16 – 18 APIo) production operations in Staatsolie's Calcutta field in Suriname can be classified as very complex since it is associated with very heterogeneous and discontinuous shallow (± 1000') reservoirs in remote environmentally sensitive wetland areas that are difficult to access as they sustain unique protected ecosystems.
To optimize productivity and mitigate the risks of operating in this complex environment, fit for purpose technologies and tailor made processes were implemented to address the challenges to:
Choose a production method that sustains a very sensitive ecosystem, ensuring efficient mobility of personnel and equipment with minimum impact on the environment, deal with the high cost of intra-field transportation, deal with the high costs of transportation of produced fluids to the nearest treating facility due to zero disposal in the swamp and dispose drilling fluids
To address these challenges the following solutions were implemented:
A wetland operations strategy was implemented whereby there was no land reclamation to setup production and surface facilities thus minimizing the impact on the ecosystem, a totally self-contained hovercraft-type drilling platform is used to drill wells in the swamp, for well servicing a fit for purpose servicing rig is used, uniquely modified Multi Phase Flow Meters for relatively low producing and low GOR wells are used and surface and subsurface facilities are remote monitored
This very unique mixture of solutions with technologies and fit for purpose processes present new perspectives in resolving particular challenges regarding the economical development of a heavy oilfield in an environmentally sensitive area.
Techniques to Improve Flow Profiling Using Distributed Temperature Sensing
Authors: Wang X. , Bussear T. , Hasan A. R. 
Published: December 2010

Abstract
The emergence of Distributed Temperature Sensing (DTS) has led to much better instrumented wells, enabling operators access to real-time temperature data. Sophisticated nodal thermal/fluid models that analyze such temperature data provide many benefits and offer valuable information. Flow profiling is one of the most important field applications of DTS.
Since temperature changes caused by fluid flow are typically small, the temperature resolution or noise level of the DTS traces becomes the limiting factor for accuracy in flow profiling. Noise can be caused by many factors, such as the time length to generate the trace and losses from optical connectors or splices. The two techniques most commonly used to reduce temperature trace noise are (1) averaging of separately measured traces; and (2) formation of a moving average along the trace (smoothing). The latter technique – smoothing – comes at the expense of a reduction in spatial resolution. Another limitation for DTS used alone for flow profiling is that it can only handle single-phase flow situations. Additional information, such as multi-point pressure data, is often needed for multiphase fluid flow profiling.
In this paper, we describe our work with Fourier series to approximate DTS traces which offers greater flow profiling accuracy and avoids spatial resolution reduction. Our mechanistic model couples energy and momentum transport, enabling us to handle multiphase flow by integrating multipoint pressure measurements with DTS.
This paper contains three field examples that demonstrate the following techniques resulting in improved flow profiling: Use of Fourier series to approximate DTS traces (Fourier Approximation);Use of Solver to determine Fourier series coefficients to minimize the sum of the squared error between the DTS traces and Approximation;Use of iterative procedures to determine the best fit overall time interval T; andIntegration of multipoint pressure data with DTS for multiphase fluid flow applications
A New Inflow Model for Extra-Heavy Crude Oils: Case Study Chichimene Field, Colombia
Authors: Arenas F. Guarin , Garcia C. A. , Prada C. A. , Leon E. Cotes , Santos N. 
Published: December 2010

Abstract
Chichimene field is a heavy oil field located in the little deformed sector known as the "foreland ‘basin plains of Colombia. This field is located in Castilla La Nueva in the Meta Department in the east part of the country. Chichimene field was discovered by Chevron in 1969 with the drilling of Chichimene-1 well (CH-1), but it only started production in 1.985. Since 2.00 Ecopetrol S.A has been in charge for field operation.
Chichimene field produces a medium crude oil (approximately 20 API) from cretaceous structures named K1 and K2, In 2.01 an extra heavy crude oil (range between 7 – 9 API) from a terciary (T2) formation named San Fernando started production with the CH-18 Well. Despite of the high density presented, the T2 crude oil is mobile at reservoir conditions due to an abnormally elevated reservoir temperature
The interest formation corresponds to an elongated northwest direction tertiary anticline layer, the crude oil discovered in this structure is extra-heavy produced by severe biodegradation and evaporative fractionation processes, the depositional model is associated to a distal marine Cretaceous rock. Nowadays the San Fernando formation produces about 14,000 BOPD using electric submersible pumps (ESP) as artificial lift method.
This paper reviewed the conditions of the reservoir (petrophysical model, PVT properties, Oil, water and gas production behavior), the physical property of the produced fluids and fluid characteristics of foamy oil properties, to establish an appropriate mathematical expression for modeling the performance of these extra-heavy oil wells.