bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Drivers in Restimulation of Gas Storage Wells
Authors: Mohaghegh Shahab , Mohamad Khalid , Popa Andrei , Ameri Sam , Wood Dan 
Published: December 2007

ABSTRACT
In order to maintain or enhance deliverability of gas storage wells in the Clinton Sand in Northeast Ohio an annual restimulation program has been in place since the late sixties. The program calls for as many as twenty hydraulic fractures and refractures per year. Several wells have been refractured three to four times while there are still wells that have only been fractured once in the past thirty years.
As the program continues many wells will be stimulated a second, third or fourth time. This paper summarizes an attempt to carefully study the response of the Clinton sand to hydraulic fractures and identify the performance drivers in each series of frac jobs. Do the performance drivers remain the same for the later fractures (second, third and fourth frac jobs) as they were in the first ones? Or do they change? This paper attempts to answer such questions.
Identification of major performance drivers becomes important when new jobs are to be designed. They not only play an important role in enhancing the response of the wells to new stimulation jobs; but also may prove to be an important economic factor in the design of new stimulation procedures. If for instance it is concluded that an increase in proppant volume does not influence the stimulation outcome after the second refracture, then fewer resources can be used for proppant volume and be directed toward parameters that are more influential.
This study employs a combined neural network and fuzzy logic tool to identify the performance drivers.
Equation for Estimating Mud Minimum Rate for Cuttings Transport in an Inclined-Until-Horizontal Well
Authors: Rubiandini R. S. Rudi 
Published: December 2007

Abstract
There are so many problems associated with cuttings deposited in the well bore when we using rotary drilling methods to drill some vertical wells, directional wells or even horizontal wells. To overcome these cuttings problems we have to determine a mud minimum rate which has a capability to clean the drilled well bore. This mud minimum rate is sum of the slip velocity and the velocity of the fallen cuttings. It is obvious that velocity of the cuttings are depend on the well bore geometry and the magnitude of the ROP. Hence this cuttings velocity will be constant for a specific well bore. This paper develops Moore's slip velocity of vertical well in order to be used in the inclined well until horizontal well with some corrections of rotary speed and the mud weight by Larsen's slip velocity procedure. The corrections of inclination angle, RPM and the mud weight are obtained from Y axis of cartessian dimensionless plotting of slip velocity with the inclination angle at X axis. Dimensionless slip velocity equals Peden's experiment slip velocity data and Larsen's calculation results for inclined well divided by Moore's slip velocity for vertical well. The paper results a new equation to determine the mud minimum rate which would lift the cuttings in the inclined through horizontal well bore. In the case of inclination angle &gt; 45°, the mud minimum rate of Larsen's method, Larsen's experiment data and Peden's experiment data have no significant difference with this new equation in the paper. On the other hand, at inclination angle &lt; 45°, the new equation results a higher mud minimum rate than all of the methods above resulted.
Organic Formation Damage Control and Remediation
Authors: Newberry M. E. , Barker K. M. 
Published: December 2007

Abstract
Organic skin damage in oil producing wells is a major factor in the loss of productivity and revenue. Paraffin and asphaltene deposition in the formation and around the well bore creates a barrier for the transportation of the crude oil to the tubing. Many producing wells have experienced a production decline that can not be explained by reservoir depletion. Organic damage may occur naturally or through various intervention practices used in the oilfield. An increased awareness of the potential for ongoing organic damage has been developing slowly over time. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection and application methods are discussed. Numerous case histories for a variety of problems are also presented.
Interpretation of Pressure Buildup Curve in Layered Reservoirs With Afterflow
Authors: Yakimov A. S. , Diyashev R. N. , Iktissanov V. A. 
Published: December 2007

Abstract
Many authors have investigated the behavior of layered systems under pressure transient test. Determination of filtration parameters by known procedures is conducted either without consideration of wellbore storage effect, or with differentiation or integration of experimental bottomhole pressure values. In either case it leads to errors in interpretation of pressure buildup curve. In this work a new technology on conductance of investigations and interpretation of results is suggested. The investigations consist in determination of flow rate from each formation in producing well, taking pressure-build-up curve and determination of crossflows between formations in shut-in well. Interpretation of pressure buildup curve is connected with numerical solution of differential equation for unsteady filtration with consideration of afterflow into the well. The advantages of suggested technology are simplification of conductance of field investigations and improvement of accuracy of determination of filtration parameters and formation pressures for layered reservoirs.
Improved Frac-Packing Method for Long Heterogeneous Intervals
Authors: White W. S. , Morales R. H. , Riordan H. G. 
Published: December 2007

Abstract
This paper presents an innovative way to uniformly frac-pack long heterogeneous perforated intervals by pumping several independent slurry schedules without shutting down pumping. The purpose is to fracture the least stressed zones first. The other zones are sequentially frac-packed thereafter. Shunt tubes are used to facilitate the slurry diversion. The shunt tubes, which run along the outside of the sand control screen, provide an alternate path for the slurry to travel in the event that proppant bridges block the traditional annular path.
Skin Self-Cleaning in High-Rate Oil Wells Using Sand Management
Authors: Dusseault Maurice B. , Waterloo A. S. , Tronvoll Johan , Santarelli Frédéric J. , Santarelli Frederic J. 
Published: December 2007

Abstract
Mechanical skin develops around high-rate oil wells because of mineral salt precipitation in the near-wellbore region, because of fine-grained minerals accumulation that block the near-wellbore pore throats, because of capillary forces development that impair free flow, and because of asphaltene or other organic substance deposition that reduces effective porosity. The removal of mechanical skin is normally carried out by workover techniques that require wellbore intervention.
As early as 1994–95, it was found that for wells in poorly consolidated sandstones many of the problems of mechanical skin could be mitigated by producing the wells at a rate that allowed periodic sand bursts, yet without initiating massive sand influx. Also, deliberate sand clean-up activities during well testing could be used to generate skin-removing bursts. The sand bursts are triggered by stress and by the increased hydrodynamic drag associated with steep exit gradients arising from skin, and they have a remarkable clean-up effect on the near-wellbore, bringing flow skin into the range of consistently negative values. Wells that are amenable to this production methodology, called Sand Management, benefit from reduced completion costs, increased production rates, lowered intervention frequency, and the development and maintenance of a negative skin.
Sand Management, in contrast to sand exclusion, requires coping with higher risks because episodic sand influx events carry with them some danger to integrity of the well and surface facilities. Risk management implies three actions: high-quality evaluation and analysis before implementation, a commitment to monitoring during production, and a process of continuous re-evaluation of the well during its production life.
These risk management activities and protocols form the basis of the Sand Management approach.
Borehole Failure: Safe Drawdown Pressures and Wellbore Damage Radius
Authors: Morales R. H. , Webb T. R. , Hollier R. 
Published: December 2007

Abstract
This paper addresses the problem of onset of failure and the subsequent development and propagation of the failed (or plastic) zone during production. It uses an elasto/plastic formulation1 to find the distance of the damaged radius for cased and uncased wells. Numerical examples and laboratory tests are used to show the onset of failure and the growth of the plastic zone.
Multiphase Flow and Drilling Fluid Filtrate Effects on the Onset of Production
Authors: Ladva H. K. J. , Tardy Ph. , Howard P. R. , Dussan V. E. B. 
Published: December 2007

Abstract
Formation damage from the drilling process must be overcome to initiate production in wells that are neither cased nor perforated. The drawdown to initiate production can be limited by low reservoir pressure, sanding potential and water coning concerns. In these cases the required drawdown to initiate flow becomes important. Published results of laboratory experiments indicate that the flow initiation pressure (FIP) increases significantly when the permeability of the producing formation is below 50mD and that it is lower for oil based drilling fluids than water based fluids1. This study presents possible explanations.
The dependence of FIP on formation permeability and drilling fluid type was evaluated both experimentally (using small cores) and theoretically. The results suggest that the relatively large FIP in low permeability cores could be a consequence of conditions influencing multiphase fluid in the experiment, e.g., core length, or whether or not the experiments were run under constant flow or constant pressure-drop conditions. Under such circumstance, the onset of production in a well may not have the same dependence on formation permeability as does the laboratory measured FIP. In addition, at least some of the drilling fluid filtrate must be removed before any of the oil can be produced. When the filtrate is aqueous, capillary forces are present. The importance of these forces could explain why the FIP is higher for water- than oil-based drilling fluids. Both experimental and theoretical results are presented consistent with this explanation.
A New Drill-In Fluid Used for Successful Underbalanced Drilling
Authors: Luo Shiying , Meng Yingfeng , Tang Hongmin , Zhou Yongxin 
Published: December 2007

Abstract
Underbalanced drilling(UBD) operations are being utilized with increasing frequency as a means of reducing invasive formation damage, minimizing problems with differential sticking and lost circulation, and increasing rates of penetration in many drilling operations, etc. However, experience has indicated that during many operations, a wide range of factors may contribute to the loss of a continuous underbalance pressure, such as pipe connection in conventional jointed pipe drilling operations, mud pulsed MWD program, tripping operations, etc. So, it is difficult to maintain a condition of continuous underbalance pressure throughout the complete operation, resulting in fluid losses to the formation and possible significant damage.
In this paper, a new UBD drill-in fluid is present. The fluid was made by adding an elastic fiber-shaped additive, calcium carbonate particles into the past UBD drilling fluid (base mud). The sizes of the fibers and particles are determined by the distribution of the pore diameters and/or fracture widths of the target formation. When overbalanced situation is happening, the fibers and particles can bridge and form a thin plugging layer in the pores or fractures in the borehole wall in 0.5 to 2.0 min, which is not more than 1 cm. This plugging layer can stop further fluid invasion into the formation. If the underbalanced situation is resumed, almost all fibers and particles can be pushed back into well from the pores or fractures by the underbalance pressure. So, this new type of fluid can minimize the possible formation damage. Besides, the results in the laboratory showed its property is similar to its base mud. Finally, a case of its application verified this type of drill-in fluid is practicable.
Thermal Performance of an Insulated Multiple Flowline Bundle Using Active Heating
Authors: Chin Y. D. , Perera R. , Prescott C. N. , Brown R. J , Cain R. E. 
Published: December 2007

Abstract
Effectively engineered flowline bundles are attractive configurations for deepwater field development, because of their thermal performance and cost effectiveness. Bundled-insulated subsea flowlines provide economic alternatives for chemical injection to eliminate or reduce the risk of hydrate, wax or paraffin formation. The purpose of this study is to investigate the thermal interaction among the flowlines and its effects on the overall thermal performance of the bundle, and on the product arrival temperature. Multiphase flow and thermal analysis procedures were conducted for the Garden Banks 216 field pipeline bundle located in the Gulf of Mexico. The investigated bundle has three flowlines that carry multiphase product fluid and heating fluid.
The flowlines are enclosed with insulation and encased in a steel casing pipe. During normal operation, the product can flow in one or two flowlines while the third is for service. When active heating is applied, hot oil will be injected into one of the flowlines at the platform. The heating oil will be circulated through the flowline and the service line, and the third line will be for produced fluid. The pigging loop will be used as the turnover loop.
This study is to determine the steady state performances of each flowline in the bundle, including the multiphase product line and two-single phase heating lines. The temperature profiles are presented for different product flowrates. The effects of product flowrate, injection flowrate and injection temperature on the pipeline temperature profiles and product arrival temperature are discussed.
Data Reinterpretation by Multidisciplinary Team Increases Gas and Condensate Reserves in Eastern Venezuela
Authors: Vega G. , Cellamare V. , Riart F. 
Published: December 2007

ABSTRACT
During many years the produced gas from Eastern Venezuela reservoirs has been one of the most important energy sources for the Venezuela internal domestic market. To support the new gas business vision, this region has in only three fields (San Joaquin / El Roble / Guario) potential gas reserve in the order of 13 MMMMSCF in 670 reservoirs. Surely, it will provide essential support and play an important role for investment to supply the necessary gas volumes for the market.
This paper, is a case study of the results obtained in the integrated study elaboration which was initiated in the RPN-24 reservoir, Merecure G sand, Roble field. The field is located geologically in the northwestern block of the Anaco thrust. Using available technologies, the revision of the data (seismic, geological and production behavior) detected the existence of a hydraulic unit with both areal and vertical comunication with other three Oligocene reservoirs.
The multidisciplinary integrated study of these mature gascondensate reservoirs revised, the existent structural model of the three cited fields, with good results. These results, through both static and dynamic model integration, identified the coalescence of four reservoirs into an unique hydraulic unit.
This integrated team process increased the GCOES to 232 MMMSCF with an average yield of 46 barrels of liquid per each MMSCF gas. Additionally, it will improve the operational process and the effective control of reservoirs by increasing the recoverable reserves.
The appropiate use of 2D seismic and the use of conventional reservoir analysis methods are always a great tool to work out studies in mature reservoirs through the application of team sinergy.
Well Test Pressure Derivatives and the Nature of Fracture Networks
Authors: Wei Lingli 
Published: December 2007

Abstract
The use of pressure derivatives in well test interpretation by reservoir engineers is commonplace since the publication on this subject by D. Bourdet et al.1 in 1989. This paper examines the relationships between well test pressure derivatives and the nature of the fracture networks within the testing region through numerous well test simulations in synthetic fracture networks.
The main parameters studied are fracture intensity and fracture size distributions. Other factors such as anisotropy, existence of faults, and matrix fracture permeability contrasts are also discussed. Numerical simulations demonstrated that where fractures are the major conduits in a reservoir, the derivatives of a pressure transient well test are a good indication of the nature of the underlying fracture networks.
For a realistic prediction of the behavior of a naturally fractured reservoir, the geologists are usually charged with characterising the fracture network based on information available from geology, geophysics, petrophysics and other measurements performed in drilled wells. This study has shown that well test and production data, normally under reservoir engineer's possession, may provide further clues about the nature of the fracture network within a reservoir, and help in extrapolating fracture data from individual wells to between wells, and ultimately within the whole reservoir.
A case study is also briefly described in this paper.
The Top 10 Mud-Related Concerns in Deepwater Drilling Operations
Authors: Zamora M. , Broussard P. N. , Stephens M. P. 
Published: December 2007

Abstract
The deepwater environment can place serious demands and constraints on the drilling fluid during well construction. Failure to adequately address these concerns can lead to excessive well costs, unscheduled trouble time, unnecessary high-risk activities, and poor performance. In this paper, we identify and succinctly discuss the top 10 mud-related concerns based on field experience in the Gulf of Mexico, off-shore West Africa, Southeast Asia, and Brazil.
Mud-related concerns selected for this top-10 list are (1) lost circulation, (2) mud properties, (3) solids transport, (4) stuck pipe, (5) wellbore stability, (6) shallow hazards, (7) gas hydrates, (8) reservoir productivity, (9) environmental issues, and (10) fluid-related logistics.
Gas Lift with Nitrogen Injection Generated in Situ
Authors: Aguilar Miguel A. Lozada , Monarrez M.del Remedios Arredondo 
Published: December 2007

ABSTRACT
Gas lift is a feasible option as an artificial lift system in a depleted field. In the Bellota field there is no substructure means to install any type of artificial lift system, therefore the use of nitrogen as a gas lift source is necessary to keep the Bellota wells producing. After evaluating different options we implemented a nitrogen generated in situ project using the membrane technology.
This paper analyzed the gas lift process design by using nodal analysis and optimum allocation of nitrogen in each well. Special emphasis and consideration was given to this project from an economical, operational, technical and environmental points of view. It is olso compares this option with differents alternatives including the traditional gas lift method using natural gas as a source as well as the use of stored nitrogen from storage trucks (Tanks). Our evaluation of results obtained from the different options investigated in this study clearly indicates that this method is a good option in this particular situation.
Nitrogen injection generated in situ with membrane technology can be a feasible and profitable alternate source of gas lift as shown in this study.
Realistic Numerical Models for Fractured Reservoirs
Authors: Gurpinar O. , Kossack C. A. 
Published: December 2007

Abstract
Characterization and forecasting in fractured reservoirs is one of the most challenging topics in the oil and gas industry. Managing such reservoirs requires construction of representative reservoir models that can handle both fracture and matrix systems, and their interaction, correctly. Data integration from all disciplines is required for construction of these reservoir models.
Commercial numerical models capable of handling flow in fractured reservoirs have been present in the industry for quite some time. However the correct application of those simulators for representative reservoir models is not easy. This paper will discuss parametric ways to improve construction of representative reservoir models. Discussion will focus on transition from single porosity representation to dual porosity models and pseudoization process employed in between.
A fractured reservoir undergoing a waterflood is simulated with a single porosity formulation, where the matrix blocks are sub-divided into core plug size grid blocks and the fractures are sub-divided into even smaller blocks. The results from this fine grid are considered the "solution" to the displacement in the fractured reservoir. The grid is coarsened and the effects of scale-up are observed. Pseudos are developed for a coarse grid so that the results match the "solution". The reservoir is then simulated with a Dual Porosity simulator. The sensitivity of the dual porosity results to the refinement of the numerical grid is studied.
A comparison is made between the "solution" and the Dual Porosity simulator results. Several of the advanced features found in commercial Dual Porosity models are tested to see how well they improve the comparison. A scale-up pseudoization is determined that allows the Dual Porosity simulation to match the "solution". A larger sector model is then simulated with the pseudo capillary pressure to investigate the robustness of the scale-up pseudoization. Recommendations are provided that describe a procedure for using the Dual Porosity Model to simulate displacements in a fractured reservoir in a more accurate way.
Characterization and Synthesis of Synthetic Drilling Fluid Shale Stabilizer
Authors: Avilés-Alcántara Cristina , Carlos Gúzman C. , Aarón Rodríguez M. 
Published: December 2007

Abstract(1–4)
Environmental constrains on disposals of cutting and drilling fluids have precluded the use of oil base mud (OBM), in addition drilling with OBM can introduce a contaminant into the reservoir. Alternative or synthetic fluids have been developed with many of beneficial properties of inverted emulsion which offer advantages beyond the fact that they are environmentally accepted. In this experimental research emphasis is given to the results of the efficiency of a new water base system, which include the use of a new shale stabilizer additive.
Anionic polymers were studied and synthesized of type anionic (ionizable groups with negative charge. It is described the synthesis of homopolymers of acrylic acid (PAA) with differen conditions of synthesis, homopolymers of AA and Dialildimetilammoniumchloride (DADMAC).
The characterization phase involves the molecular weights and viscosities determination for homopolymers AA and molecular weights by an alternate method for copolymers of AA-DADMAC, use of I.R. spectroscopy for the structure elucidation.
To prove the efficiency of the system were developed CIC test, swelling and dispersion test (by using cores from the Gulf of Mexico basin), rheology HPHT, filtration tests, TSC, lubricity.
The results of the describe experiments involved in the hydration of shale. Experimental details and results will be presented.