bluuebunny/crossref_metadata_2025 huggingface dataset:
Full, Short-, and Long-Time Analytical Solutions for Hindered Matrix-Fracture Transfer Models of Naturally Fractured Petroleum Reservoirs
Authors: Rasmussen Maurice L. , Civan Faruk
Published: December 2007

Previous matrix-fracture transfer models overlooked the hinderence effect of the fracture surface conditions on petroleum recovery from naturally fractured reservoirs. These models are simplistic and do not represent the matrix-fracture transfer with sufficient accuracy.

This paper presents improved matrix-fracture-transfer models and approximate analytical solutions for petroleum recovery from naturally fractured reservoirs. The restricted and hindered matrix-fracture interface fluid transfer phenomenon is considered in order to account for the finite-skin effect of the matrix block surfaces by various processes, including the formation of a stationary fluid film or an actual skin because of formation damage by various processes, such as deposition of minerals and other debris, and adverse rock-fluid interactions. The slab, matchstick, parallelepiped, cylindrical, and spherical type simpler shapes are considered to represent the matrix blocks formed by intersecting fractures in petroleum reservoirs. Then, full scale, and short- and long-time analytical solutions are presented. The analytical solutions are derived also for special boundary conditions involving the rectangular and cylindrical shape rock samples used in typical laboratory tests to represent the matrix blocks. The functional behavior of the transfer functions is demonstrated using various charts and the practical straight-line plotting schemes are presented for effective interpretation of experimental data.

The present model can accurately represent the matrix-fracture interface fluid transfer over the full range of the fluid recovery period, while the previous models can only represent either the early- or the late-time behavior with limited accuracy. The present analytical solutions can be instrumental in developing effective and accurate simulation of oil and gas productions from naturally fractured reservoirs. The new models provide alternative matrix block shapes, skin effect of the matrix block surface, and variable shape factors. Whereas the previous models primarily assumed constant shape factors, ignored the skin effect, and considered a few simple block shapes. The new improved transfer functions are advantageous because these consider variable shape factors and are applicable for primary recovery of gas or oil reservoirs involving single-phase flow and waterflooding or secondary recovery of oil reservoirs involving two-phase flow. The special analytical solutions developed for laboratory core samples can be used for interpretation and evaluation of the results of laboratory core tests.
New Rheological Correlations for Guar Foam Fluids
Authors: Khade Sudhakar D. , Shah Subhash N.
Published: December 2007

Foams provide highly attractive alternative over conventional non-Newtonian fluids for various oil and gas industry applications because of their high viscosity and low liquid content. Foams have long history of proven performance in well stimulations, drilling, acidizing, cleanout operations, and enhanced oil recovery. Foam apparent viscosity is used in hydraulic (pressure drop) calculations for various pumping operations. Thus, accurate rheological characterization is very important to predict viscosity of foam.

In this investigation, rheological experiments are carried out with guar gel and guar foam fluids rheology using a ½-in. pipe viscometer at 1000 psi and temperature ranging from 100 to 200 °F. Guar, surfactant and nitrogen are used as the gelling agent, foaming agent and gas phase respectively. Foam formulations were prepared and tested for qualities ranging from 0 to 80 % at several flow rates.

The present study has shown that both guar gel and guar foam fluids exhibit a behavior analogous to the Power law model fluid. The experimental data are used to develop new rheological correlations to predict Power law fluid flow parameters and thus, apparent viscosity of the foam fluids. These new correlations are functions of temperature, foam quality, shear rate, and fluid concentrations. The correlations were compared with various published correlations. The available correlations in the literature have assumed that the flow behavior index of the foam is similar to that of the liquid phase. This assumption does not support the basic physics that the increase in viscosity decreases flow behavior index. Our results show that the above assumption is not valid and leads to a prediction of extremely low apparent viscosity of foam fluids. In contrast to the previous studies, we report high apparent viscosities of foam fluids at high qualities.
A Successful Methanol Treatment in a Gas-Condensate Reservoir: Field Application
Authors: Al-Anazi Hamoud A. , Walker Jacob G. , Pope Gary A. , Sharma Mukul M. , Hackney David F.
Published: December 2007

A field test was conducted to investigate the effectiveness of methanol as a solvent for removing condensate banks that form when pressure in the near wellbore region falls below the dewpoint. Core flood experiments on Texas Cream Limestone and Berea cores show that condensate accumulation can cause a severe decline in gas relative permeability, especially in the presence of high water saturation. This can result in well productivity declining by a factor of 3 to 5 as bottom hole pressure declines below the dewpoint. PVT analysis performed on field samples taken from the Hatter's Pond field in Alabama indicate retrograde condensate behavior. These high-temperature deep gas wells show low gas productivity and large skin. A preliminary analysis of the data indicated the possibility of condensate and water blocking due to the loss of water-based drilling fluids. Core samples were used to measure gas relative permeability. Compatibility tests were conducted to ensure that the injection of filtrate and methanol did not cause any damage to the core. Since the formation brine is very saline, tests were conducted to check for salt precipitation during methanol injection. Based on these laboratory results and a single-well numerical simulation, a field test was conducted. The well chosen for treatment was producing 250 MSCFPD with 87 BPD of condensate. A thousand barrels of methanol was pumped down the tubing at a rate of 5 to 8 B/min. Gas production increased by a factor of 3 initially and stabilized at about 500 MSCFPD. Condensate production doubled to 157 BPD. The well shows a skin of –1.9 after methanol treatment. The increase in gas and condensate production was observed to persist more than 10 months after the treatment.

Several possible explanations are provided for the positive results obtained in this test. Some general conclusions are made for the design for future treatments.
Laboratory Evaluation of High-Temperature Conformance olymer Systems
Authors: Vasquez Julio , Civan Faruk , Shaw Thomas M. , Dalrymple E. Dwyann , Eoff Larry , Reddy B. R. , Brown David
Published: December 2007

This paper presents the results of laboratory evaluation regarding the effectiveness of novel, organically crosslinked, high-temperature, conformance polymer gel systems as sealants. Effectiveness of these sealant gels is evaluated by attempting water flow through high-permeability cores under residual oil conditions. The effectiveness of the sealants to (1) block water permeability at temperatures up to 350°F, (2) provide long-term sealant properties at these temperatures, and (3)provide adequate gel time for placement is measured. The ultimate goal is to determine whether the selected crosslinked polymer systems provide useable extended gel times and maintain thermal stability to 350°F.

Discussed are (1) the physical laboratory model and test conditions used to perform dynamic core flow studies over extended periods in determining the impact of sealant exposure to elevated temperatures and subsequent required modifications, (2) experimental procedure used for dynamic core flow studies, (3) the effect of temperature on permeability reduction over time, (4) the impact of threshold pressure (differential pressure required before fluid flow begins through a treated core) on permeability reduction over time, (5) laboratory methodology used for gelation time measurement of a new, novel, organically crosslinked, high-temperature, conformance polymer gel system, and (6) laboratory results regarding gelation time of the polymer system as a function of temperature up to 350°F.
Well Performance in a Previously Condemned Prospect: The J Sand Formation in the Northeast Wattenberg Field
Authors: Khachatrian Mikael B. , Trippett Steve W.
Published: December 2007

The J Sand formation is a main pay zone in the extensively developed Wattenberg field of Colorado. Until recently, operators deemed the reservoir in the northeast part of this field uneconomical due to significant production of formation water in this low permeability and sub-pressured gas zone. By modifying the conventional completion techniques of the J Sand, an operator relatively new to the area has been able to economically exploit this reservoir. Key factors that have contributed to the success include improvements in stimulation design and production techniques. Typically, hydraulic fracture stimulation treatments for the J-Sand utilize a low viscosity, guar based, zirconium crosslinked fluid pumped at injection rates up to 24 bbl/min. The above operator differs in stimulation design by incorporating a higher viscosity, low polymer carboxy methyl guar fluid pumped at a relatively low injection rate (e.g. 12 bbl/min). Well performance evaluations utilizing the Reciprocal Productivity Index (RPI) production analysis method in conjunction with log analysis quantify stimulation effectiveness. Treatment pressure history matching with 3D fracture simulators also identify advantages in achieved fracture geometry and proppant placement with the modified treatment design.
Re-Fracturing: Evaluation, Design, and Implementation of a Chester Oil Well in SW Kansas
Authors: Sauer Paul W. , Burns Richard A. , Skees James L. , Aud William W. , Gentry Brooks , Wing Chad
Published: December 2007

This paper will highlight the methodology used to successfully re-stimulate a well that had been unsuccessfully stimulated from previous treatments. A field example will present a well, which was previously treated on two occasions and show the subsequent implementation of a successful treatment that displaced both Ottawa and resin coated sand from the original fracture, enabling the third treatment to be successfully pumped. The initial evaluation methods that were utilized, which included pressure buildup (PBU), reciprocal productive index (RPI), and treatment pressure analyses, will show the damage that can occur when overly aggressive stimulation treatments are applied and present a methodology for evaluating a damaged well. A treatment was specifically designed to remove the proppant pack damage and create an effective stimulation for the character of the reservoir rock. The pressure response from the third treatment will demonstrate removal of the original and the creation of an effective stimulation. Post-treatment production data and analysis is also presented.
Optimization of the Producing Wells (Acidizing-PLT)
Authors: Boussa M. , Bencherif D.
Published: December 2007

Production - Pressure - Skin - PLT - Permeability - Porosity – Acidizing - IP

The field of Hassi R' mel is a gas condensate reservoir with a superposition of three layers A - B - C having very good petrophysic characteristics and a rather significant oil rim in the Eastern and Southern peripheries.

Producing wells were drilled in the Northern part - Central - Southern with two lines of dry gas injection.

A decrease in production of the wells was observed in the various zones. Build up tests realised on those wells showed significant skin, which is due primarily to the excessive invasion of the mud used during drilling and Work overs.

For that, a study was undertaken in order to see the method to be used for optimisation and to improve the potential of these wells, which is less than that hoped within sight of their petrophysic characteristics.

A stimulation by acidification was decided and 3 companies were selected.

34 wells were realised during this campaign, which was carried out in 3 phases in order to diversify the methods.

1st phase 13 wells; 2nd phase 13 wells; 3rd phase 8 wells.

In order to study the effects of stimulation, PLT's were realised before and after the acidizing.

The purpose of this presentation is to show:

The resulted synthesis of the PLT's carried out on the acidized wells will be analysed and shown in the form of tables and graphs which will enable us to draw a conclusion on the advantages and disadvantages from this stimulation campaign.
Fourteen Years of Progressing Cavity Pumps in a Southern Oklahoma Waterflood
Authors: Oglesby Kenneth D. , Arellano Jose Luis , Scheer Gary
Published: December 2007

The West Hewitt Penn Sand Unit, a waterflood in southern Oklahoma, has utilized progressing cavity pumps (PCP) since September 1988. Producing zone depth is approximately 2100′ with PCP producing rates of 200 to 1100 BPD per well. Through an evolution of PCP configurations and designs a 4+ year pump life can be expected, with only minor repairs. Adjustable rates at the surface, low capital costs, low repair costs and high electrical efficiency are the attractive characteristics of this artificial lift method. Improved identification of elastomer compatibility with reservoir fluids / conditions; improved prediction of stator-rotor fit over time; and reduction of top rod / drivehead breaks are the remaining challenges to improving PCP performance.
Single-Phase Model for ESP's Head Performance
Authors: Sun Datong , Prado Mauricio
Published: December 2007

This paper presents a new incompressible single-phase model for ESP's head performance. Sachdeva (1988) and Cooper (1966) developed models for ESP channels [1, 2] and for inducers [3], respectively. The model presented in this paper is based on one-dimensional approximation along an ESP channel. The new derived pressure ODE (Ordinary Differential Equation) for frictionless incompressible flow is consistent with the pump Euler equation. New models for pump frictional and shock losses have been proposed. Finally, a comparison between the predicted pump performance and the pump performances from Affinity Law for different rotational speeds is presented. The single-phase model can predict ESP performance under different fluid viscosities and also is the basis of gas-liquid model for ESP's head performance.
The Rocket Science Behind Water Frac Design
Authors: Grieser Bill , Hobbs Jimmie , Hunter Jeff , Ables Jerry
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Carbon Dioxide Geological Sequestration: Technical and Economic Reviews
Authors: Nguyen Duy Nghia
Published: December 2007

Geological sequestration is a potential technology to reduce large amount of greenhouse gas emissions which are essentially carbon dioxide (CO2) released from stationary industrial sources such as petroleum extractive plants or fossil-fired power plants. Sequestering CO2 from a natural gas development involves separating CO2 from hydrocarbon gases, dehydrating and compressing CO2, transporting it via pipeline to injection site, re-compressing if applicable, injecting it into geological reservoirs and monitoring its movement and behaviour after sequestration. Chemical absorption using amines is the most widely used technology to date for separating CO2 from natural gas. Current researches focus on other technologies, especially membrane technologies. Reservoir and geology studies are to optimize the sequestration process and to predict the movement of the injected CO2 in the reservoirs. Monitoring the injected CO2 after sequestration is to ensure that CO2 is retained in the reservoirs.

The costs of sequestration could vary from below US$5 to over US$20 per tonne of CO2, which largely depends on the amount of CO2, distance and reservoir properties. Economic results are in favor of large CO2 flow rate, short distance and high injectivity reservoirs. These costs exclude the separation costs which are considered to be part of the natural gas processing because CO2 must be reduced to a certain level (e.g. 2% by volume) before selling the natural gas even if no sequestration is needed. Cost per tonne of CO2 sequestered could be translated into the incremental costs of producing natural gas if we know the CO2 volume fraction in raw natural gas. For instance, as a rough estimate, sequestering the CO2 from a 25% CO2 by volume raw natural gas field would increase the costs of natural gas production by US¢9/Mcf to US¢35/Mcf of processed natural gas.
Biological and Volatile PAH Losses During Aerobic Slurry Phase Biotreatment
Authors: Fairey Julian L. , Loehr Raymond C.
Published: December 2007

The suitability of an aerobic biological treatment process for the removal of PAH from a creosote contaminated field soil was evaluated. Specific objectives were to determine: a) the overall loss of specific PAH, b) losses due to volatilization, c) the effect of possible operating temperatures and microbial acclimation, and d) the relationship between volatile losses and solid-liquid and liquid-gas partition coefficients. The results indicated that an active aerobic biotreatment process is a suitable treatment process for these contaminated soils. Overall losses that occurred were: 2-ring PAH, 99-100%; 3 ring PAH, 86-100%; 4 ring PAH, 41-44%; and 5-ring PAH, 26-37%. There was little difference in PAH removal at 20°C and 35°C. Volatile PAH losses did occur. The maximum PAH loss was for naphthalene and ranged from 9 to 17%. For most of the other PAH, overall volatile losses were less than 1% and commonly in the 0.1 to 0.9% range. There were no volatile losses for some of the 4 ring PAH and for all of the 5 ring PAH that were measured. Volatilization became less of a factor as microbial acclimation occurred. The study documented that, in an aerobic treatment process with an active acclimated microbial population, microbial degradation of SVOC will be the primary loss mechanism. Several predictive relationships were determined between PAH volatile losses and liquid-gas (KH) and solid-liquid (KOW, KOC) PAH partition coefficients.
Ultra Short Radius Drilling Trials in PDO
Authors: Al-Hady Abdullah Saif , LaPrad David , Al Sadi Anwur
Published: December 2007

Productivity from thin reservoir layers and thin oil rims can be enhanced by short laterals, fully contained within the layers. Ultra short radius system will be required to kick off and drill these lateral within the reservoir. Now days, these system are available as Rotary Steerable system 4-8 m and jetting system (0.5 m). This paper will discuss the flexible pipe rotary system, in particular the Torch drilling services (TDS) system and the implementation of this system in PDO.

This system has been tried two times last year in Lekhwair field. In both wells a dual lateral have been drill and completed as open hole injector. The paper will discuss this the technology concept, describe the tool and drilling procedure and will summarize the operational aspect of the trial. Couple of trials will be planned this year (2003) to complete the evaluation of the system.
Gas Migration After Cementing Greatly Reduced
Authors: Jennings Scott S. , Al-Ansari Adel A. , Al-Yami Abdullah S.
Published: December 2007

Gas migration through cement columns has been an industry problem for many years. The most problematic areas in Saudi Aramco operations for gas migration are in deep gas wells (Khuff / pre-Khuff) in the Ghawar field.

Gas migration in deep gas wells occurs when drilling through the base of Jilh dolomite. To control gas influx, cement densities required to successfully cement this zone could be as high as 170 pcf. Specially designed cements were used to "zone isolate" the high pressure coming from the formation. High density/low fluid loss cements were used in the past with limited success. More recently, Liquid Latex in combination with expanding additives have been used to help reduce the gas flow potential before and after the cement sets.

The objective of this study was to develop effective cement formulations to control deep gas migration during primary cementing and optimizing costs of expensive cement additives. Three major physical properties lab equipments were utilized for this study. First, a cement gas migration system (CGMS) was utilized to measure gas flow through a cement column prior to the setting of the cement. Second, the static gel strength analyzer (SGSA) was used to determine the static gel strength of well cements to confirm the data from the CGMS. Third, the American Petroleum Institute (API) expansion cell was used to determine the expansion properties of set cements. Data from the CGMS, SGSA and API expansion cell was successfully utilized to greatly reduce the gas migration problem. The consumption of expensive cement additives (latex and expansion) in the cement formulations were optimized for cementing gas wells with success. The in-house cement design optimization saved the company as much as 59% on the cost of obtaining the desired cement fluid properties.
Reservoir Simulation of Gas Injection Processes
Authors: Lawrence J. J. , Teletzke G. F. , Hutfilz J. M. , Wilkinson J. R.
Published: December 2007

In reservoirs with favorable rock and fluid properties, application of gas injection processes can enhance the recovery efficiency and value of a field development. ExxonMobil employs a systematic approach to evaluating and selecting recovery processes during the full life-cycle of each reservoir. Once a gas injection project has been implemented, ongoing surveillance programs and optimization studies are performed to ensure that maximum value is obtained from the resource. One important aspect of managing these resources has been the use of reservoir flow modeling to understand performance expectations and to develop reservoir management strategies to optimize recovery.

Because ExxonMobil's experience with reservoir simulation of gas injection processes has covered many types of injection processes over many years, a full suite of simulation approaches has been used for reservoir flow modeling. The gas injection processes studied and implemented have included miscible floods, immiscible floods, Water-Alternating-Gas (WAG) floods, as well as gas disposal. A full range of injection gases such as CO2, H2S, N2 and hydrocarbon injectants has been used. The fit-for-purpose simulation approach is chosen based on specific needs and objectives for each reservoir. The approaches have ranged from coarsely-gridded black oil simulation to finely-gridded compositional simulation depending upon the specific requirements for a given field. In recent years, the emphasis has been on state-of-the-art compositional simulation. ExxonMobil has applied compositional simulation to design and manage more than 25 gas injection projects covering the full range of injectants and lithologies.

Because each gas injection project is unique, the evaluation of benefits must be comprehensive and adaptable. Case studies are presented illustrating a range of gas injection processes and reservoir types. The case studies highlight important aspects of data collection, issue identification, simulation technique evaluation, process evaluation, and long-term project stewardship.
Water Injection and Water Flooding Under Fracturing Conditions
Authors: Noirot J. C. , van den Hoek P. J. , Zwarts D. , Bjoerndal H. P. , Stewart G. , Drenth R. , Al-Masfry R. , Wassing B. , Saeby J. , Al-Masroori M. , Zarafi A.
Published: December 2007

With the realization that water injection is generally taking place under fracturing conditions, tools capable of better modelling fractured injection and its impact are being developed. Models integrating rock (fracture) mechanics and traditional reservoir simulation are now applied to water injection projects with a number of applications in the Middle East. Fracture dimensions are a key input to those models. Monitoring techniques to track the evolution of induced fractures with time are also being deployed. Amongst those techniques microseismic and specific fall-off test procedures are used.