bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Performance of Multilateral Wells
Authors: El-Sayed Abdel-Alim H. , Amro Mohammed M. 
Published: December 2007

Abstract
Advances in drilling and completion techniques have allowed drainage of reservoirs via tile use of multi-lateral well arrangements in a variety of configurations. The most important aspects to consider regarding the application of multi-lateral wells are the potential cost benefits and potential risks of utilizing the technology. Difficulties exist in predicting the performance of multi-lateral well arrangements. Many of the performance prediction difficulties are being addressed through different projects.
This paper presents detailed equations to be used for calculating production rate of multi lateral holes both planner and stacked. It discusses the factors affecting the production rate in comparison to a horizontal well. Also, the paper introduces a proposed reservoir and calculates the productivity of that reservoir.
T.R.A.M.S. – A New Standard for Rig Audit Inspection, Management and Sharing
Authors: Thomson Ian W. , Hay Douglas G. 
Published: December 2007

Abstract
Independent rig inspections or audits are widespread within the industry for a number of reasons. They help assure the contracting operator that costly down time is minimised but, more importantly, that the unit is ultimately safe for operations. Major problems exist with current systems. There is a lack of a standard and information is often outdated before the audit report is delivered to the client. The T.R.A.M.S. system has been designed to allow strategic planning, management and implementation of the drilling unit inspection. All historical information is held within a database, which is organised to encourage the sharing of this information across the industry via the World Wide Web. The database is updated with advancement reports allowing details to be followed as the audit progresses.
Blow out Occurrence Caused by Annular Gas Flow after Cementing
Authors: Kadry Khaled 
Published: December 2007

Abstract
Recently Pliocene and Miocene gas discoveries in offshore Mediterranean were achieved. Octopus complex structure is one of the shallow structures that exhibits a well pronounced rollover phenomena where multi bright spots (targets) are present on its crystal part. The well OCTOPUS # 1 DIR is proposed in portfouad development lease to check the potentiality of the Pliocene and Miocene sequence.
The paper discusses the blow out occurrence in said well, after the 2nd stage has been cemented and during final cut 9"5/8 casing. The 9"5/8 casing was set to cover all the high pressure interval where the maximum pore pressure is expected to be (1.75 kg/cm2/10m). And also discusses why the well stopped blowing out after 3 HRS by it self, the damage which has been happened due to cement blowing out, the operation done to replace the damaged well head and BOP stack to rescue the well. And will be discusses also the operations done to resume the drilling operations, some of these operations include, recording TDT - TEMP. Log to establish possible gas pockets trapped behind the casing, recording USIT to identify bridging, gas bucket, and fluid type behind casing. The paper discusses also annular gas migration, and the operation done to investigate and find out the reasons, which contribute to create this type of problem, and the preventive methods recommended avoiding this type of problem. Some of these methods include, adjusting cement column height, adjusting slurry thickening time, applied surface pressure on the annulus during W.O.C. increase annular mud density prior cement job, add gas block to the cement slurry, increase cement slurry mix fluid density, predicts annular gas migration by graph.
Cementing under Extreme Conditions of High Pressure and High Temperature
Authors: Shaheen Mansour , Schulz Jo , Haddad Gaby S. , Helou Husam 
Published: December 2007

Abstract
Wells are classified as High Pressure/High Temperature (HPHT) when BHT (Bottom Hole Temperature) exceeds 250°F (121°C).
Although cementing of all wells is very important and should follow a certain engineering methodology to ensure success, there are some differences related to cementing conditions and the consequences of failures of HPHT wells as compared to normal wells. This paper reviews those differences along with the specific methodology to design, execute and evaluate cementing operations in HPHT wells.
Success factors, such as accurate well data, BHT prediction, optimized fluids and job execution criteria are discussed.
Tools utilized to optimize factors affecting cementing HPHT wells are presented, such as temperature simulator, job design simulator, American Petroleum Institute (API) and specific laboratory testing, Right-Angle-Set cement slurry, mud removal, mixing energy, on-site QC (Quality Control) checks, contingency planning and post-job proper evaluation.
The Charco Redondo Steam Flood Pilot -Reservoir Monitoring Operations
Authors: Widmyer R.H. , Howard C.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The Charco Redondo steam flood was a fully instrumented pilot conducted to determine heat losses, formation heat content, location of formation and injected fluids with time, and residual oil saturations. The data acquired confirmed the ability to predict heat losses and thermal front predict heat losses and thermal front movement. The oil saturation in the flooded reservoir was reduced to approximately 9%.

Introduction
Thermal recovery methods are used to improve production of heavy viscous crude oils. Steam injection is one method used extensively for both pushpull and throughput flooding pushpull and throughput flooding operations. In either application, prediction of reservoir behavior during prediction of reservoir behavior during steaming is necessary so steam generation requirements and costs can be estimated. The Bellaire Research Laboratories performed a fully instrumented experimental steam flood in the Charco Redondo Field, Zapata County, Texas, to verify methods for estimating these requirements. The primary objectives were to determine primary objectives were to determine (1) radial heat losses from the injection well, (2) vertical heat losses to adjacent formations, (3) movement of the various fluids, and (4) residual oil saturations after the steam flood.

RESERVOIR PROPERTIES
Reservoir properties are itemized in Table 1.
PATTERN PATTERN As shown in Figure 1, a 1.01 ha (2.5 acre) isolated inverted five-spot pattern was selected. Injector No. pattern was selected. Injector No. 111 and Producers No. 112, 113, and 114 were drilled to complete the pattern in conjunction with existing pattern in conjunction with existing Well No. 84. The sides of the square pattern were 100.6 m (330 ft). pattern were 100.6 m (330 ft). PRODUCER AND INJECTOR COMPLETIONS PRODUCER AND INJECTOR COMPLETIONS The producers were completed in 20 cm (7-7/8 in.) holes with 14 cm (5-1/2 in.) O.D. casing cemented in place with high temperature cement.
Recovery of Chuc-A Platform Wells at the Campeche Bay, Mexico
Authors: Rodríguez Arturo G. , Martínez Humberto C. 
Published: December 2007

Abstract
The Chuc-A production platform produced an average of 59,200 BPD until October 24th 1997, in this date a fire happened when installing a separator. This oil volume corresponds to the 43% of the field total production. Once the fire was controlled, the personnel of the Drilling Management and Wells Maintenance proceeded to inspect the area with propose to prepare a plan to control wells.
In this paper the operative program and the developed activities to mend wells are shown, incorporating them to production. The activities have been divided in three stages: a) wells control after damage and change of valves to the production trees damaged by fire, leaving them in safe conditions, b) control of wells for the Chuc-A platform restoration and c) Tubing recovery, cut and change of wellheads and production trees, tubing pipe introduction and new subsuperficial safety valves (SSV), stimulation, production surveys, and beginning of the production. Besides, a list of materials, services, safety equipment, logistic and human resources is included which are necessary for the wells recovery.
To carry out the repair operations of all the wells, a total of 387 days was necessary, with a total cost of 15.7 MMUSD, being the rent of equipment the biggest percentage equal to 54.8%. The costs related to services were equal to 4.6 MMUSD, and the costs of materials reached to 2.5 MMUSD. At the end of the operations the eight flowing wells were incorporated to production with similar flow rates to the original ones.
Between the first and the second stage, the wells were set in production during six months while the necessary materials and services were acquired for the final repair of wells.
Optimization of Gas-Well Completion and Production Practices
Authors: McMullan J. H. , Bassiouni Z. 
Published: December 2007

Abstract
In water drive gas reservoirs, wells can be completed with a long perforated interval and produced at high rates to minimize abandonment pressure and maximize recovery. Alternatively, the perforations can be limited to the top of the productive interval and the well produced at a low rate in an effort to prevent coning which results in high abandonment pressures if the strength of the aquifer is adequate to support reservoir pressure. This study uses a reservoir simulation coning model to evaluate these two conflicting completion and production practices. The impact of completion interval, gas production rate, and reservoir permeability were evaluated.
Ultimate gas recovery was found to be largely insensitive to variations in perforated interval and production rate in high permeability systems. Ultimate water production, however, was found to increase at high gas rates and lengthened perforated intervals. In lower permeability systems, ultimate gas recovery was found to increase significantly as production rates were increased, while ultimate water production was actually observed to fall. Sensitivity analysis of vertical to horizontal permeability ratio, fluid density contrast, relative permeability, and formation dip did not alter these conclusions.
The conclusion that elevated production rates can be expected to have no detrimental impact on ultimate gas recovery suggests that gas rates should be maximized in low water disposal cost situations. This finding favors the completion of an interval sufficiently long to maximize production rate and thereby insure that gas recovery and present value of gas reserves are maximized. In high water disposal cost situations, however, it should be recognized that this strategy might result in elevated water production in high permeability systems.
Production Analysis of Commingled Gas Reservoirs - Case Histories
Authors: Arevalo-Villagran Jorge A. , Wattenbarger Robert A. , El-Banbi Ahmed H. 
Published: December 2007

Abstract
A method to match and forecast production rates for commingled gas wells has been developed. In this paper, the method previously developed by El-Banbi and Wattenbarger1,2, was improved and extended to allow modeling of recompletions and different initial pressures in the layers. This new method is based on a layered model that couples the material balance gas equation with the real gas boundary dominated flow equation for each layer of the multilayer-commingled system.
A spreadsheet-based computer program was developed and used to analyze the production history of commingled wells. The program calculates the individual original gas in place, OGIP, productivity index, Jg, and production rates for each layer. It also forecast the production rates of individual layers and the total well. Bottom-hole flowing pressure, pwf, total gas rate history, gas properties, and initial reservoir pressure for each layer are required.
The parameters OGIP and Jg for each layer are determined by history-matching the total gas rate using a nonlinear optimization procedure. This new method gives excellent results for cases dominated by stabilized flow, with occasional shut-ins and substantial pwf variations. The method calculates back-flow between layers during shut-in periods. Although this method is based on using stabilized flow in history-calibration data, validation against numerical simulation shows that the method can tolerate many transient flow periods caused by variations in producing conditions. Several wells were used in testing this method. Five Mexican wells are included in this paper.
Propped Fracturing in Gas Carbonate Formations in Mexico
Authors: Aguilar-Razo R. 
Published: December 2007

Abstract
Since 1995 Pemex E & P has been using acid fracturing to increase production rates in gas-condensate fields in carbonate formations at the Veracruz Asset. The increase in production from fractured wells is an average of 0.5 MMCFD per well. Trying to enhance the fracturing activities, the Veracruz Multidisciplinary Team made a proposal for a project for the application of propped fractures. The project is part of an internal process named Technology Management Process, PAT per its Spanish acronym, conducted and supported by the Technology and Professional Development Subdirection. In Mexico, all the propped fracturing activities were conducted in sandstone formations, especially in its North border, and hence the importance of this work. The project includes 3 propped fractures in fields Mata Pionche, Mecayucan and Copite. In 1998 the well Mata Pionche 1092 was fractured, but the job suffered a premature screenout after 55% of the proppant mass had been placed in the formation. In spite of the screenout, a net increase of 0.2 MMCFD was achieved, not enough to recover the investment in a short time.
This paper presents a Post-Frac analysis of well Mata Pionche 1092 treatment, independent of the Service Company's report. It was finished 12 months after the treatment to include the production response over a considerable period. This paper includes the causes of such screenout concerns and describes multiple fracture geometry using several tools. Although these tools are used to obtain data differently, they are not used in Mini Frac and main treatment data together. This paper will show that the effective use of the combined analysis is more comprehensive.
It is possible to apply successfully propped fracturing in carbonate formations with some modifications to the perforation program, selection of fracturing fluids and flow efficiency testing to diagnose potential problems.
Producing Rich-Gas-Condensate Reservoirs--Case History and Comparison Between Compositional and Modified Black-Oil Approaches
Authors: El-Banbi Ahmed H. , Forrest J. K. , Fan L. , McCain W. D. 
Published: December 2007

Abstract
This paper presents the results of a full field simulation study for a rich gas condensate reservoir with complex fluid behavior. Unique to this paper is a comparison between Modified Black-Oil (MBO) and compositional simulation in a full field model with water influx. Geological, petrophysical, fluid properties, rock-fluid properties, and well data were used to build two full field simulation models (14-component Equation-of-State, compositional model and 3-component MBO model). More than 14 months of daily gas, oil, and water production and tubing pressure data from 4 wells were matched using the MBO model. The model was then used to forecast production and identify new development locations. Comparison runs between the MBO and the fully compositional models were made. It was found that the two models agreed for the entire simulation above and below the dew point and with water influx from the aquifer. The MBO runs were at least 5 times faster than the most efficient compositional run.
The use of the MBO approach allowed a rapid history match of the field performance and a timely completion of the simulation study. Contrary to the common belief that a compositional simulation approach is needed for modeling near-critical reservoirs, this study shows that a MBO approach can be used instead of a fully compositional approach for modeling depletion and water influx processes in near-critical reservoirs. This approach may result in significant time saving in full field simulation.
Permeability Mapping on Vuggy Core Sample Using Tracer Experiments and Stream-Line Simulations
Authors: Moctezuma-Berthier A. , Fleury M. 
Published: December 2007

Abstract
Carbonate rocks have complex porous structure and conventional approach to characterize two phase flow in the laboratory can be inadequate, especially in vuggy structures. Various laboratory studies indicate that centimeter scale heterogeneities have important effects. An important question is the determination of the 3D permeability map later used in the interpretation of two phase flow experiments.
Our approach is based on the combined use of CT scan 3D porosity maps, NMR relaxometry, tracer experiments and numerical simulations to derive a 3D permeability map consistent with the experimental observations. NMR T2 measurements are used to quantify the average porous volume represented by the vugs while CT scan can reproduce the spatial distribution of porosity at the millimeter scale. The permeability map is mainly deduced by fitting the tracer experiment using 3D numerical simulations where we introduce the CT scan porosity map and where the permeability in each grid cell take only two values, one associated with vugs, and one with the matrix.
The study was performed using a volcanic rock (Andesite) with 22% porosity and low permeability (0.4 mD) to mimic a non fractured vuggy carbonate. The variogram analysis in the flow direction does not indicate a correlation of the porosity map. However, the tracer experiment indicates the existence of a preferential path and the measured flux dispersion behaves as in a layered system (early breakthrough, long tail). For a given volume fraction of vugs (congruent with NMR results), the experiments can be reproduced with numerical simulation by adjusting the permeability contrast between the matrix and vug to 360. The use of a streamline simulator was necessary because of the large number of grid cells used and low numerical dispersion. Finally, miscible displacement experiments using different viscosity fluids are interpreted and discussed using three models considering heterogeneity and viscosity.
Integrated Reservoir Characterisation of a Fractured Carbonate Reservoir
Authors: Guerreiro Luis , Silva Antonio Costa , Alcobia Victor , Soares Amilcar 
Published: December 2007

Abstract
One of the most important issues for the characterisation of a reservoir and the assessment of the fluid flow behaviour is the role of faults, fractures, and micro-fractures. At different scales these reservoir features have a tremendous impact on the reservoir drainage and in the overall productivity of the field1.
Faults can compartmentalise the reservoir into different units and the design of the production plan has to account for that. Fractures can be the main path for fluid flow and can strongly affect the production drive mechanism. Micro-fractures have a significant impact on permeability enhancement and drainage areas. The reservoir model should take into account all these features in order to reproduce the internal reservoir architecture and provide a reliable input for the numerical simulation of the fluid flow.
This paper proposes a methodology for integrated reservoir characterisation incorporating micro-fractures and fault analyses. A case study is presented for the characterisation of the reservoir properties and geometry and for the integration of micro-fractures in the final reservoir model.
Laboratory Monitoring of Surfactant Imbibition Using Computerized Tomography
Authors: Chen H. L. , Lucas L. R. , Nogaret L. A. D. , Yang H. D. , Kenyon D. E. 
Published: December 2007

Abstract
Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering water-oil interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A good agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption. Single and multi-well pilot tests at Yates also demonstrated oil recovery improvement and water-oil-ratio reduction in response to dilute surfactant treatment.