bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Rocket Science Behind Water Frac Design
Authors: Grieser Bill , Hobbs Jimmie , Hunter Jeff , Ables Jerry 
Published: December 2007

Abstract
The popularity of water fracs has increased in recent years. The reduction in fluid cost and overall fracture stimulation cost has in some cases revived exploration in low-permeability reservoirs like the Barnett shale in north central Texas. Water fracs have also been used effectively in reservoirs with low permeability and large net pays, which require large volumes of fluid to attain adequate fracture half-lengths to achieve commercial production.
In the past, the design of water fracs has been more of an art than a science. While the term "water frac" implies that the fluid is proppant-free, in most cases some proppant is usually pumped. The amount and concentration is usually low when compared to conventional fracture treatments. Water-frac designs are further complicated by the fact that fracture geometry, conductivity, and proppant transport are not easily modeled.
Despite these difficulties, the attractiveness of water fracs requires the implementation of a design methodology. This paper discusses a design procedure for water fracs from a field operation/design standpoint. Volume and rate requirements are discussed for a specific zone height, desired fracture length, and aerial width. A fracture width vs. proppant size requirement is applied, and a simple material balance calculation is performed to generate a fracture volume taking fluid leakoff into account. Fracture conductivity of a low proppant-concentration, high fluid-volume fracture is estimated to optimize proppant length and fracture conductivity ratio (Cfd). A pump schedule is generated based on the results of the previous calculations. All design calculations are simple and require only a handheld calculator or simple spreadsheet.
The design model was calibrated to a microseism-mapped Cotton Valley Lime test well. A leakoff coefficient multiplier was used to calibrate the model. The model-predicted volume was then compared to actual volume on a second Cotton Valley Sand test well and on a 10-well average Barnett shale microseism fracture-mapping data set. The overall model-predicted volume for the mapped microseism geometry is compared to actual volume pumped.
Coal Seam-Well Cementing in Northeastern Oklahoma
Authors: Huff Curtis D. , Merritt Jerry W. 
Published: December 2007

Abstract
Successful primary cementing of coal seam wells requires slurry design considerations that conventional cementing operations typically do not consider. The unique petrophysical and geological properties of coal must be factored into the design in order to meet the basic tenets of primary cementing, i.e., zonal isolation and casing support. This paper focuses on coal seam wells cemented in the northeast Oklahoma shelf.
Cement slurry design is a critical part of any successful cementing operation. This is particularly true for coal seam wells where the unique nature of coal places additional demands on the cement. Slurry design considerations and successful slurry formulations for the area will be discussed along with an overview of primary cementing practices. Operational considerations as they apply to cementing coal seam wells in the study area will also be discussed. Conclusions and recommended practices for optimum results will also be presented.
Case History of Drilling a Directional Well in the Arkoma Basin
Authors: Bilyeu B. , Lindecke J. , Hicks T. , Varcoe B. , Cheatham C. 
Published: December 2007

Abstract
This paper discusses the planning and drilling of Big Prize #2-20 well, drilled by BP America in South Panola Field of the Arkoma Basin in Oklahoma. Wells previously drilled in the field have been prone to problems with lost circulation and stuck pipe, high drillstring torque and drag, low ROP, and directional control. The primary causes of these problems are the hard and fractured formations, steeply dipping formation beds, and small geologic targets. To reduce drilling time and cost, major changes were made to standard drilling practices in the area. The major changes were contracting a state-of-the-art land rig, modifying the drilling fluids program and surface treatment, using steerable motors from surface to total depth (TD), replacing mud-pulse MWD with electromagnetic (EM) MWD for the first time in the field, and employing premium drill bits. The result was substantial reduction of drilling time and cost. The Big Prize #2-20 well was drilled to a TD of 15,850 ft measured depth (MD) in 70 days compared to 96 days for the offset well drilled on the same pad to a similar depth, which represented an improvement of 26 %.
Surface Chemistry of Oil Recovery From Fractured, Oil-Wet, Carbonate Formation
Authors: Hirasaki George , Zhang Danhua Leslie 
Published: December 2007

Abstract
Oil recovery by water flooding in fractured formations is often dependent on spontaneous imbibition. However, spontaneous imbibition is usually insignificant in oil-wet, carbonate rocks. Sodium carbonate and anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks. Crude oil samples must be free of surface-active contaminants to be representative of the reservoir. Calcite, which is normally positively charged, can be made negative with sodium carbonate. The ease of wettability alteration is a function of the aging time and temperature and the surfactant formulation.
Performance of Trinidad Gas Reservoirs Cassia, Immortelle, Flamboyant, Mahogany, Amherstia and Teak
Authors: Hallam Richard , Kin Maria Lum 
Published: December 2007

Abstract
The Cassia, Flamboyant, Immortelle, Mahogany, and Amherstia fields currently produce over 1.4 bcf/d for the Trinidad domestic gas market and Atlantic LNG Projects (Trains I and II). By early 2004 the gas rate should increase to about 2 bcf/d when two new projects start-up. These fields, plus the older Teak field are located in the Columbus Basin off the southeast coast of Trinidad.
The six fields have produced gas from 35 reservoirs, which are at depths from 5,084 ft tvdss to 13,000 tvdss, and with initial pressures from 2305 psi to 7420 psi. The production data show that the gases are condensates, with yields that vary from 1 b/MMscf up to 50 b/MMscf.
The reservoirs exhibit a number of production mechanisms, including volumetric, volumetric with compartmentalization (due to faulting), water-drive (weak to strong aquifers) and waterdrive with compartmentalization. These reservoirs generally produce at high initial rates (50 – 247 MMScf/d).
The paper shows examples of each recovery mechanism and reports the gas and condensate recovery factors. In addition, the paper documents the reserve distribution for the reservoirs, the number of wells required to develop each reservoir, and the well rates.
Installation and Data Analysis of a Downhole, Fiber Optic Flowmeter at Mahogany Field, Offshore Trinidad
Authors: Kragas Tor K. , Johansen Espen S. , Hassanali Hamid , Da Costa Shelley L. 
Published: December 2007

Abstract
In March, 2002, a downhole, fiber optic flowmeter was successfully installed in BP's Mahogany A-15 well, offshore Trinidad. The meter was installed at a measured depth of 12,114 ft and a deviation of 71°. The flowmeter is full bore, completely non-intrusive, contains no downhole electronics or moving parts, is electrically passive and was deployed with the production tubing string during completion of the well. It provides high quality measurements of temperature, pressure, gas flow rate, and oil flow rate directly to the platform SCADA system. In addition, data from the instrument is linked to BP's Wide Area Network through a network-accessible hard drive. The installation at Mahogany was a field trial of the flowmeter and represents a number of "firsts" for deployment of fiber optic flow metering technology, including the first application metering a downhole flowing gas phase and the first multiphase application.
Performance of the flowmeter at Mahogany has exceeded expectations and demonstrates the value of real-time downhole production data. Data quality of the fundamental meter measurements of pressure, temperature, bulk velocity, and mixture sound speed from the first nine months of operation has been excellent and within specifications. The high deviation of the well at the meter location, along with a rapid increase in downhole free gas fraction, presented several interpretation challenges, including operation in complex flow regimes and slippage of the oil phase relative to the gas phase at the meter. This was resolved through development and implementation of a pseudo-three-phase slip model. The resulting downhole oil, gas, and water rates from the flowmeter are converted to surface rates using appropriate PVT data before being passed to the SCADA system. Thus far, rates from the downhole optical flowmeter agree with surface well test results to better than ±10%.
Integrated Approach to Sand Control Delivers Zero Sand
Authors: Travis Mike , Tovar Juan , Chambers John L.C. 
Published: December 2007

Abstract
Sand production is a serious historical production problem in the Forest, Cruse and Nariva reservoirs of the Gulf of Paria offshore Trinidad.
Venture Production Trinidad drilled, completed and tested 10 wells in 2002. Sand production has been no more than a trace in all but one of the tests so far.
Sand control has been undertaken without recourse to the traditional mechanical methods of sand screens and gravel packs. A carefully planned approach integrating modern methods of well-bore stress analysis and sand production prediction from log interpretation has delivered this result. A well-bore stress study reviewed all available data from the Brighton Field, including old drilling reports and logs. The study has been updated with modern data from the 2002 drilling programme. A well-bore stress model was developed. A sand prediction study delivered an understanding of the mechanics of sand production in the area which was fed into the well-planning process. Well data and logging data were analysed with very short turnaround times to deliver a sand production prediction log. Perforated intervals were selected using the log to avoid intervals with a high probability of sand production. Perforating techniques were also selected to minimise the likelihood of sand production without compromising productivity.
Characterising Reservoir Performance for the Mahogany 20 Gas Sand Based on Petrophysical and Rock Typing Methods
Authors: Ali-Nandalal J. , Gunter G. 
Published: December 2007

Abstract
The Mahogany Field in Trinidad produces ∼475 MMscfd and is the sole supplier of the gas to Atlantic Liquefied Natural Gas (LNG) plant's train 1. The Mahogany Field's gas reserves are dedicated to the LNG plant. The original reserve calculations assumed volumetric depletion would be the dominant drive mechanism for the gas reservoirs in this field.
Four years later, water drive is the dominant drive mechanism for all sands except the 20 Sand. If the 20 Sand eventually shows water drive, the predicted rate profile and reservoir management would be different than if it had been a volumetric reservoir.
This study investigates both drive mechanisms and makes recommendations for managing the reservoir in either eventuality. To support this work, a petrophysical description was carried out. This included rock typing of the reservoir and calibrating the wireline log data with 20 Sand core. Three independent methods for rock typing were employed, two of which have not been used on offshore Trinidad core samples previously. A facies description was compared to the rock type classifications and flow units.
A reservoir simulation model was built using log analysis from the 20 Sand and incorporating the results of the petrophysical descriptions of the different rock types and flow units.
A history match was obtained for the well currently draining this reservoir and predictions on the 20 Sand incorporating a future 7″ horizontal gas well were also done. The recovery factors were obtained for the reservoir under different drive mechanisms – volumetric and water drive. Recommendations for optimal reservoir management of the 20 Sand are given.
Formation Damage Evaluation by Means of FRT Test
Authors: Mucci Marcela Z. , Moreyra Juan D. , Porta Carlos 
Published: December 2007

Abstract
To maximize the production and enhanced total recovery of hydrocarbons, the oil companies must have a complete understanding of the reservoir rocks and fluids present in their producing fields.
The measurement of rock properties enables us to determine its ability to allow fluids to flow and understand the way these fluids will behave when the reservoir is produced. This information provides the starting point to conduct a Formation Damage Analysis that will lead to an appropriate diagnosis in order to select the best solution. It will provide detailed explanation to the problems that well and production have and will offer basis and support to the stimulation treatment investigation and its effects.
The Formation Damage is any mechanical, chemical, biological or thermal process in a reservoir that causes a reduction in porosity and permeability.
Almost all the field operations constitute a potential source of damage for the well productivity that often results in reduced productivity of oil or gas reservoirs or reduces injectivity of injection wells, on a secondary recovery.
This paper is an attempt to supply a preparatory methodology to enable the potential risks of formation damage evaluation, trying to correlate the results in a laboratory scale with the field test.
The laboratory diagnosis, usually preliminary for stimulation, help auspiciously to avoid or decrease the risk of damage.
The study and control of formation damage requires a test design consistent with the feasibility of the operatives options and involves properties such as the knowledge of geological and petrophisics of the formation to be stimulated, fluids compatibility, operative procedures, etc.
Approach to Successful Workovers in Karachaganak Gas Condensate Field
Authors: Al-Shammasi Ali A. , D'Ambrosio Angelo 
Published: December 2007

Abstract
Optimizing Workover plan and completion procedure for the Karachaganak reservoir brought superior results and created development opportunities for the reservoir. The new approach is based on rigless investigation, data integration and innovative methods to overcome different well problems.
Karachaganak field is a giant gas condensate field located in the north west of Kazakhstan. The structure is sealed with a salt layer that varies in thickness across the field. Salt that are not fully protected could creep causing casing collapse especially if subjected to negative differentials.
Initial well design applied on the 240 exiting wells imposed limitations on workovers. Additional field challenges are; severely corroded and potentially stuck completion strings, poorly cemented casing, and scale deposition.
The new approach has been developed over more than four years of operations. Successfully, workover time has been reduced by more than 25%, saving about $850,000 per workover. Well risk identified and failure risk is minimized. Well abandonment recognition, planning and cost have been optimized.
Thin Oil Rim Development in the Amherstia / Immortelle Fields, Offshore Trinidad
Authors: Bayley-Haynes Erica , Shen Eugene 
Published: December 2007

Abstract
Effective exploitation of the thin oil rim in the Amherstia / Immortelle 22 sand is particularly challenging because of the size of the overlaying gas cap, 2TCF, and the thickness of the oil rim varying between 31 to 46 feet gross pay interval. Since oil wells in the thin oil rim of the 22 sand did not justify well cost, the challenge, then, was to make the oil wells more attractive to facilitate early depletion of the oil rim.
Reservoir simulation work was undertaken and a joint team was formed to evaluate the reservoir performance and determine the best strategy for depletion. This team consisted of subsurface professionals from the Amherstia and Immortelle fields, and the bp Houston technology group. The performance of the two wells in the reservoir was history-matched and then the model was used to develop an improved strategy.
The reservoir simulation grid used was aligned with the major fault patterns and nested local grid refinement was utilized to better understand depletion of the oil rim. Sensitivity analysis conducted demonstrated that locating longer horizontal oil wells with larger size tubing in the upper third of the oil rim proved to be the best strategy for depletion of the oil rim. The strategy provided higher production rates with earlier accessibility to gas reserves while outrunning the aquifer.
State of the Environment: The Challenges Facing the Energy Industry Sector in Trinidad and Tobago
Authors: Jaggernauth Deonarine D. J. 
Published: December 2007

Abstract
The emergence of the petroleum, petrochemical, refining, and processing plants, among others during the past one hundred years in Trinidad has impacted on the environment. Vegetation has been removed to accommodate these industries and at the same time the ecosystem was disturbed. The wildlife, birds, insects and other reptiles had to venture into other areas convenient to their lifestyle. The tributaries, which continue to empty into the major rivers nearby, have been affected by either sediment or effluent from the various plants and this has interfered with the aquatic life.
Indeed the country would like to continue receiving cheap abundance of gasoline; the country would like to lead the world in the exportation of ammonia, urea, methanol, liquefied petroleum gas; people would like to have a choice of what soaps, detergents, plastics, or other by-products they use; but everyone must be mindful of the adverse effect these and other industries are having on the environment.
During the last ten years there has a closer view on the impact industries are having on the environment. The new industries that are emerging have more stringent rules and laws to follow now, than the ones that were constructed during the last century. Reports such as the Environment Impact Assessments, and Base Line Studies now play an integral part in the application to construct a new plant. Companies now have to apply for Certificate of Environmental Clearance before any new plant can be built, new well can be drilled, and existing plant can be modified, expanded or abandoned.
The many industries, including the energy industry, that exist in Trinidad have changed the landscape of the environment both in a positive and a negative manner. But now there is a culture evolving namely "we cannot operate like we did in the past." Indeed, profit is the controlling factor for the energy industry to survive, but not at the expense of the environment. The paper presented herein looks at the challenges facing the energy industry as it tries to survive the stern tests of the environmentalists.
Improving the Performance of Risk Analysis Applied to Petroleum Field Development
Authors: Ligero Eliana L. , Costa Ana Paula A. , Schiozer Denis J. 
Published: December 2007

Abstract
The appraisal phase in a petroleum field is characterized by several uncertainties, high investment and critical decisions, which are always strongly related to risk. In the past, it was usual to realize production forecast based on a deterministic simulation model. However, production forecast obtained by a probabilistic approach allows the quantification of uncertainty in the reservoir performance by numeric flow simulation of several possible models. Current hardware permits to incorporate more accurate production prediction in the decision processes. A probabilistic approach requires the definition of a methodology. The objective of this work is to develop a methodology to improve the performance of the risk analysis process, trying to get the best accuracy with the lowest number of simulation runs, using an automated process and parallel computing to accelerate the process. The methodology is based on simulation of several flow models representing possible scenarios of the reservoir, through the combination of the uncertain attributes. As simplification, sensitivity analysis is made to reduce the number of uncertain attributes. The simulation models are built through the derivative tree using only the critical attributes. To reduce the simulation time, parallel computing is also applied. After simulation of the models, a statistic treatment is used to obtain the risk curve of the production forecasts and of the net present value. Representative models are selected to integrate the analysis with economic uncertainties. The methodology is applied in petroleum fields and the advantages of the automated process and the simplified procedure are discussed.
Challenging the Limits: Setting Long Cement Plugs
Authors: Regan Sankar , Vahman Jurai , Ricky Ramroop 
Published: December 2007

Abstract
In the recent past (last 1 ½ years) within bp Trinidad and Tobago (bptt) operations there has been a need to plug and abandon long sections of well bores in order to isolate hydrocarbon-bearing zones. The basic method of obtaining isolation is setting a balance cement plug. Current industry practices recommend the maximum length of a cement plug as 900 ft. With the need to plug back openhole sections greater than 2000 ft, there is a challenge to efficiently isolate these long intervals. This efficiency is dependent on the technology and best practices currently existing and more importantly compliance with local regulations and bp's policy. Bptt in conjunction with a number of service providers experimented with and investigated several options including the use of "conventional" cement plugs, sacrificial string with an openhole packer and a hydraulic release tool, coil tubing and long cement plugs. The paper will demonstrate that an understanding of the key risks involved in an operation allows for questioning the industry accepted practices and hence challenge these limits. Appropriate pre-planning and risk mitigation guides the development of a procedure that facilitates extending the length of cement plugs beyond current best practices. This is justified by the analysis that shows extending the length of cement plugs to1800 ft is the best solution for isolating long openhole sections based on economics, efficiency and risk.