bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing the Number of Components in Tuning the Peng-Robinson Equation-of-State for Trinidad's Gas Condensates
Authors: Raffie Hosein , Tennyson Jagai
Published: December 2007

The volumetric performance of gas condensate reservoirs is needed for designing processing facilities. A tuned Equation-of-State can be used for suitable evaluations. The required data for tuning are dew-point pressure, gas produced, liquid dropout and gas deviation factor, which are experimentally derived from Constant Volume Depletion Tests. Tuning by regression is the most common form and involves adjustment of the questionable Equation-of-State Parameters so as to obtain the best match between predicted and experimental data. Publications on tuning have not demonstrated the effect of using varying number of components and fixed weight factors to apply for best prediction.

The Peng-Robinson Equation-of-State was tuned to match Constant Volume Depletion data for several Trinidad gas-condensate samples. The optimum number of components required for best prediction was investigated in stages, starting from C7+ and using three sets of tuning parameters. The upper and lower bounds for each tuning parameter were fixed so that they remain physically realistic. The weight factors assigned to each experimental data set were kept constant for every sample. Apart from liquid drop out, excellent predictions were obtained when Binary Interaction Coefficient between methane and the heavy carbon groups were tuned to match dew point pressure. By including the parameters of Oa and Ob for methane and Oa and Ob for the last carbon group excellent prediction of liquid drop out was attained.

This paper demonstrated that an optimum number of components are required for best prediction of Constant Volume Depletion data, with errors less than 10 %. The required number was different for each sample studied and varied from a minimum of C15+ to a maximum of C25+. A higher number can reduce this accuracy of prediction. Some consistency in tuning, with regards to tuning parameters and weight factors was also demonstrated and resulted in less time and effort required. This approach can be equally applied to other gas condensate samples.
A Look at Batch Drilling in Trinidad and Tobago
Authors: Boodoo Craig , Dwarkah Denison , Rajnauth Jerome
Published: December 2007

Over the last decade, batch drilling has become increasingly prevalent in the petroleum industry as large and small investors alike seek to increase their profit margin. The perception of many of these oil companies was to drill and complete wells in batches with the hope of significant reduction in developmental cost for the field. That is, similar hole sections of different wells were drilled one after the other, the thinking being that efficiency and profits would be greatly increased.

One would therefore ask the question: Could batch drilling be used to develop marginal amounts of petroleum reserves anywhere in the world?

With respect to the experiences in Trinidad and Tobago, we have seen from several batch drilling projects that this type of drilling exercise may not be economical because of the geological makeup of our reservoirs.

This paper looks at the experiences of two such batch-drilling projects in Trinidad and Tobago and explores the cost effectiveness of such drilling, in our very complex and uncertain geology.
Knowledge Management: Key Drivers For An E&P Program
Authors: Caligari Rubén
Published: December 2007

In many organizations, knowledge management (KM) plays a central role in the process of value creation, and terms such as "intellectual assets" are now popular in business literature. Sometimes, however, companies find it difficult to shape KM concepts into a specific program.

This paper presents a KM program developed and implemented for an E&P company. With solid management commitment, the program utilized currently available human resources and existing, installed technology. Three key drivers led to the program's success:

Moving from the abstract to the concrete: Identify KM advocates, and choose knowledge examples clearly linked to the bottom line.

Focusing on content rather than platforms: Define knowledge that is critical to the business, and identify those within the organization who can furnish that knowledge.

Promoting cultural change: Transform the cultural paradigm by redefining everyone's value in the organization.

Specific programs developed for knowledge sharing are discussed, as well as use statistics and the importance of incentives. In spite of the difficulties in identifying program results, the need to define metrics is also addressed. Finally, results, difficulties and challenges faced during the first year of implementation are described.
The Top 10 Lost Circulation Concerns in Deepwater Drilling
Authors: Power David , Ivan Catalin D. , Brooks Steve W.
Published: December 2007

Many of the technical challenges of drilling in deepwater have been well documented in the literature. One of the primary concerns is the narrow operating window between pore pressure and fracture gradient that often results in major fluid losses when drilling, running casing, and cementing. Deepwater fracture gradients are typically much lower than those encountered onshore or in shallow water (Fig. 1) thus preventing losses in deepwater can be more difficult.

Failure to minimize lost circulation can greatly increase the already high cost of drilling, as well as risking loss of the well. Successful management of lost circulation in deepwater should incorporate identification of potential loss zones, optimization of drilling hydraulics, and clear, easy to follow procedures should lost circulation be encountered.

The aim of this paper is to review the top 10 concerns associated with lost circulation in deepwater environments. This top 10 list addresses the causes of lost circulation and recommended solutions for managing these problems. Based on experience in various deepwater basins around the world, including the Gulf of Mexico, Brazil, and West Africa, the top 10 concerns are (1) sub-salt rubble zones, (2) locating loss zones, (3) seepage losses, (4) drilling, running casing and cementing with synthetic-based drilling fluid, (5) drilling practices, excessive rate of penetration and hole conditions, (6) wellbore breathing (ballooning), (7) low temperature drilling fluid rheology, (8) inadequate shoe tests, (9) synthetic-based fluid compressibility, and (10) well control.
Improving Desalting Performance By Installing Proprietary Internals In An Existing Vessel- A Case History
Authors: Movafaghian Shaya , Chen James , Collins Tom
Published: December 2007

An existing desalting train at U.S. Golf Coast region refinery was consuming excessive chemicals and encountering frequent operation and maintenance problems. Effluent water from the desalter also contained high oil concentration which overtaxed refinery's waste water treatment plant.

After careful evaluation and analysis of the existing desalting system, replacement and modification of the vessel internal was recommended.

This paper is a testimony to the performance of the Bilectric™* desalter and its operational and economic advantages. The payback for the capital investment was less than one year and economic justification was proven by several months of actual operating data. Some of the saving sources reported by the refiner were, lower chemicals usage, lower power consumption, lower oil concentration in the effluent water and lower maintenance cost.
Improving Wellbore And Formation Cleaning Efficiencies With Environmental Solvents And Pickling Solutions
Authors: Curtis James , Kalfayan Leonard
Published: December 2007

The purpose of a chemical stimulation treatment, be it based on acid, solvent, or other systems, is to remove formation damage and increase productivity/injectivity, by restoring or improving the reservoir permeability in the near-wellbore region. A fundamental preliminary step in most successful matrix stimulations is a tubing cleanout commonly referred to as a pickling treatment. A tubing pickle is often necessary to remove mill scale, rust and other iron deposits from the tubular walls, in order to prevent their injection into the reservoir with detrimental effects to permeability. The pickling treatment also prevents the spending of the subsequent chemical treatment; the creation and injection of damaging precipitates; and the formation of iron-induced sludge in the reservoir. Common pickling solutions include corrosive hydrochloric or acetic acid. Additionally, the pickling solution often contains a hazardous organic solvent and surfactants to remove asphaltene or wax deposits and damaging pipe dope residues.

Such hazardous pickling solution is reversed out of the tubing and recovered at surface where it must be neutralized, treated and properly disposed of. The surface handling of the recovered pickling solution poses significant safety and environmental hazards, due to its acidity and toxicity. A very common hazard is the release of deadly hydrogen sulfide gas in the return tank due to the reaction of the acid with iron sulfide scale deposits in the tubing.

This paper discusses the use of a neutral pickling solution, containing environmentally favorable derusting oxidizers, surfactants and solvent solutions/dispersions, which also prevent the liberation of hydrogen sulfide gas. This paper also presents an analysis of the chemical mechanisms of this solution, some treatment design guidelines, and its technical, safety, environmental and economic benefits, compared to conventional pickling solutions. An environmentally-favorable solvent replacement for the conventional aromatic solvent will also be discussed. Successful case histories in a variety of environmental pickling and other applications will be reviewed.
Effects of Permeability and Wettability Heterogeneities on Flow in Porous Media
Authors: Marcelle-De Silva Jill , Dawe Richard A
Published: December 2007

Waterflooding is the most widely used form of enhancing oil production from oil and gas reservoirs. Since all hydrocarbon reservoirs are heterogeneous, it is necessary to understand the physics associated with flow in these reservoirs to better predict production performance, and to allow for the proper placement of injection and production wells. This paper focuses on effects of well-defined heterogeneities on the immiscible displacement processes.

Flow experiments were performed using two-dimensional visual models packed with unconsolidated glass beads, and having carefully controlled permeability and wettability heterogeneities. The immiscible displacement experiments demonstrated the significant effect of such permeability and wettability heterogeneities on flow patterns, residual saturations and recoveries. In some instances, during waterflooding experiments, high permeability regions were bypassed due to capillary pressure differences. Nodal crossflow was also observed.

These results can be used to validate the results of numerical simulators and x-ray CT scanning. They can also be used to assist in the understanding of actual reservoir production performance under immiscible type displacement processes.
Advanced Cutting Structure Improves PDC Bit Performance in Hard and Abrasive Drilling Environments
Authors: Mensa-Wilmot Graham , Penrose Bill
Published: December 2007

The performances of PDC bits in hard formations, especially when these formations are also abrasive, still lack effectiveness and consistency. In such applications, the industry has usually resorted to the use of "insert type" roller cone (RC) and impregnated diamond bits (ID) – due primarily to their performance consistencies.

Impregnated bits, usually, exhibit the durability characteristics needed to drill long footages in hard and abrasive formations. However, due to their grinding rock removal action, penetration rates (ROP) are typically low, commonly in the (3 – 9 fph) range. These low ROPs experience rapid deteriorations, once argillaceous and/or shale bearing formations are encountered. These conditions reduce the operational efficiency of impregnated bits, driving up drilling costs.

From an ROP perspective, roller cone bits perform better (6 – 12 fph) than impregnated bits in hard and abrasive formations. In addition, the ROPs of RC bits experience minimal decay in argillaceous and/or shale bearing formations. However RC bits are commonly tripped on hours and, do not exhibit the longevity needed for hard and abrasive environments. Considering the depths at which such hard and abrasive formations are usually encountered, trips increase operational hours, HSE risk and thus substantially add to drilling cost.

Due to their depositional depths, hard and abrasive formations are sometimes encountered in HP/HT environments. This condition often necessitates the use of high mud weights, or BHA's that incorporate high speed drive mechanisms - PDMs or turbo-drills. Such conditions, necessary to improve operational efficiency, further complicate the drilling environment - affecting the ROP and/or durability of all drill bits.

This paper discusses an innovative PDC bit, which has specifically been developed to improve operational efficiency in hard and abrasive formations. This new generation PDC bit effectively addresses the ROP limitations of impregnated bits, as well as the footage deficiencies of roller cone bits. In addition, these bits have been developed to be effective, even when hard abrasive formations are drilled with high mud weights and/or with high speed drive mechanisms.
The Ocean Drilling Program: Leg 207
Authors: Radford T. S. , Radford S. S.
Published: December 2007

The Ocean Drilling Program, ODP, will end in 2003 when it will be replaced by the Integrated Ocean Drilling program.

Leg 207 is the first of the last group of 4 legs to be drilled by the ship JOIDES RESOLUTION.

From January to March 2003 4 sites are being explored on the Demerara Rise on the Surinam Margin, Western Equatorial Atlantic Ocean.

Water depths range from 1895 to 3215 metres. The sites have been imaged with high resolution, multichannel seismic lines supplemented by industry lines.

Stratigraphic control is provided by Site 144 of the Deep Sea Drilling Project Leg 14, Shell well Demerara A2-1 and Paleogene cores from the METEOR cruise 49/4.

Oozes, chalks and black shales from an expanded Cretaceous - Paleogene section at shallow burial depths are being investigated for stratigraphic boundaries and Oceanic Anoxic Events.

These results will be of significance to deepwater exploration for hydrocarbons offshore Trinidad, Venezuela and the Guianas.
A Novel Approach to Hydrogen Sulfide Removal From Natural Gas
Authors: Fidler Brandy R. , Sublette Kerry L. , Jenneman Gary E. , Bala Greg A.
Published: December 2007

Sulfide removal is a significant problem in the oil and gas industry. Some of the problems presented by sulfides include environmental compliance, toxicity, corrosion, reduced efficiency of fluid handling equipment, offensive odor, reduced value of products, and increased operation costs. Microbial oxidation of sulfides offers the potential for a safe, cost-effective method of removing sulfides from natural gas, sour water, spent-sulfidic caustic, etc. The purpose of this study is the development of an efficient and economically viable bioreactor system for sulfide oxidation. The application of immediate interest is the removal of H2S from "stranded" natural gas.

The immobilization matrix Bio-Sep® has previously been used for successful biotreatment of BTEX-contaminated groundwater. In this study, a special sorbent has been added to Bio-Sep® to adsorb sulfide while still maintaining the desirable physical properties of the original beads. Thiobacillus denitrificans is a sulfide-oxidizing autotroph which may use either oxygen or nitrate as a terminal electron acceptor. Thiosulfate, elemental sulfur, or sulfide may be used as an energy source for T. denitrificans and each are oxidized to sulfate. Previously, suspended cultures of T. denitrificans were shown to remove H2S from a gas stream with 1-2 s of gas-liquid contact time. However, the volumetric productivity of suspended cultures was insufficient to lead to an economically viable bioreactor design due to low biomass concentrations. In order to increase biomass concentration and volumetric productivity T. denitrificans has been immobilized in both standard Bio-Sep® and the new sulfide-sorbing version (Bio-Sep®S). The two matrices will be compared according to their ability to immobilize this sulfide-oxidizing culture and increase biomass concentration and volumetric productivity.
In-Situ Thermal Remediation of Contaminant Below the Water Table
Authors: Elliott Lucas J. , Pope Gary A. , Johns Russell T.
Published: December 2007

In-Situ Thermal Desorption (ISTD) is a soil heating remediation technology currently applied primarily to remove organic contaminants from the vadose zone. It has been shown to be effective in the clean up of a wide range of contaminants from volatile organics to heavy oils. A removal on the order of 99.99% of the contaminants has been documented in several field tests. This is a very robust technology that could prove invaluable in the remediation of saturated zone contamination. To date, however, there has been little research into the feasibility of its application when contaminants are located in the saturated zone. To this end, two-dimensional numerical simulations using a commercial reservoir simulator were performed. The contaminant type, aquifer permeability, and hydraulic gradient are some of the factors that may affect the use of ISTD in the saturated zone. Simulations were run varying these parameters to ascertain their effects upon process performance. The results show that it is possible to use ISTD in the saturated zone and that the remediation time is dependent upon these factors.
New PDC Technology Saves Operator $4.7 Million Drilling Challenging 8-1/2" Directional Hole Section
Authors: Al-Suwaidi Abdullah S. , Soliman Ahmed Abou , Zeinoun Klink , Isbell Matt , Dykstra Mark , Jones Christopher , Hoss Parham
Published: December 2007

Roller cone bits have dominated the 8-1/2" steerable application in Abu Dhabi due to their proficient steerability, consistently achieving the required build rates in the soft Nahr Umr shale. In the vertical section, PDC bits often achieve up to four times the penetration rates of TCI bits. However, directional performance when using PDC bits to build angle was compromised by fluctuations in reactive torque resulting in poor tool face control and inconsistent build up rates. The overall result was poor penetration rate and performance compared to roller cone bits. The operator and a service company utilized a new design process and cross functional team approach to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantage of PDC bits. This process was complemented by the Well Delivery Limit process (WDL) that was already established by the operator that focused on delivering high value wells with significantly reduced costs. The team analyzed the drilling operations from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology. After 72 bit runs from November 2001 to December 2002, the team reduced drilling costs by $39.21 per foot for a total savings of $4,780,530 over 121,916 ft and 3227 drilling hours. The average ROP for the section doubled from 18 ft/hr with TCI bits to 37.78 ft/hr. The current ROP record stands at 60 ft/hr over a 3,169 ft interval.
A Simplified Hole Cleaning Solution to Deviated and Horizontal Wells
Authors: Bizanti M. S. , Alkafeef S. F.
Published: December 2007

Well bore bottom hole cleaning is an essential problem to be recognized when drilling oil or gas wells. Poor or under designed well hydraulics will lead to poor bottom hole cleaning. Slip velocity correlation's have been developed in the past fifty years and recommendations of proper annular velocities have been suggested in order to prevent slippage of drill cuttings around drill collars and around the drill bit which in turn lead to regrinding of these cuttings causing a waste of the limited energy available to the drill bit. An average annular velocity of 80-120 ft/min has been seen in the oil industry to satisfy the criteria of the proper well bore cleaning.

Drill cuttings transport in deviated and horizontal wells has been examined in the laboratories and factors effecting cutting bed forming have been examined previously. In this paper a simple method predicting the minimum mud pump flow rate required to lift cuttings in a deviated holes and horizontal sections is proposed. The variables required in determining the minimum flow rate are: hole diameter, angle of deviation, plastic fluid viscosity, yield point, mud weight, cutting specific gravity, and the rate of penetration.

The propsed method was checked against field values and has produced excellent results. The proposed methodology of the hole cleaning in the deviated and the horizontal wells can be utilized as a quick tool in future hydraulic designs.
An Effective Means to Control Lost Circulation in Flowing HPHT Wells- Case History from East Med Sea Area
Authors: Medhat Sanad , Arshad Waheed
Published: December 2007

High pressure/high temperature (HPHT) wells can present a myriad of challenges including lost circulation, well kicks, underground blowouts, or other mechanical constraints before a final target depth of 12,000 ft or more is reached. Thereafter, the bottomhole environment with temperatures of 300+deg F and pressures exceeding 10,000 psi test the limits of hardware and chemicals. Each operational misjudgment or tool malfunction can impact the well costs significantly. For example, the pipe trip time to correct such problems can run into twelve to twenty four hours of non-productive time.

This paper addresses a well control issue in a HPHT exploration well where a possible underground crossflow was in progress and the well was losing oil-based mud. Several days were spent trying to control the well by using various fluids (some conventional and others new) but with no success. Eventually a new, Wellbore Pressure Containment Improvement System (WPCIS) was implemented, and it controlled the losses effectively. The well had been losing at an ECD (equivalent circulating density) of 16.4 ppg. Application of the WPCIS process improved the wellbore pressure containment (WPC) side of the mud weight window to sustain an equivalent of 17.0 ppg mud as measured by a formation integrity test (FIT). This remarkable WPC improvement was achieved along with several other cost saving factors.

The discussions in this paper will further reveal the workings and applicability of the WPCIS as a process that can help optimize well plans leading to lower costs for drilling fluids, casing design, cementing, and completion equipment.
Permeability Upscaling on Corner-Point Geometry in the Near-Well Region
Authors: Ding Y.
Published: December 2007

In this paper, a technique for upscaling of absolute permeability in the well vicinity on CPG (Corner-Point Geometry) gridblocks is presented. The near-well upscaling procedure is very useful for well performance prediction. It can assure the coherence of well results by using fine grid on coarse grid simulations.

The near-well upscaling procedure is developed for advanced wells in 3D. Transmissibilities are upscaled from Cartesian fine grid issued from a geostatistical to CPG coarse grid used for flow simulations. To overcome the difficulty of complex geometrical intersections between fine gridblocks and coarse gridblocks, three approaches (geometrical approach, numerical approach and topological approach) are proposed and compared for flux upscaling. The topological approach, which needs a topological structure for gridblock regrouping in the vertical direction, seems the most promising. The near-well formation damage, which can be predicted using another numerical model, can also be integrated into the near-well upscaling procedure.
Sand Management by Using Ultrasonic Systems at Deep and Ultra Deepwater Installations
Authors: Aldal Dag A. , Instanes Geir , Dahl Tonje
Published: December 2007

This paper offers an introduction to sand production problems in the petroleum industry and the challenges of overcoming them, including the principles of operation of ultrasonic clamp-on sand monitoring systems and why they should be installed subsea rather than topside. It demonstrates how operators can optimize production by using such systems and discusses the savings involved. A description of a field trial illustrates the difference between a subsea and a topside installation to explain the difference in measurement quality and the risks involved due to sand production. It also focuses on how operators optimize production by means of sand monitoring systems and the resulting savings, using actual figures from sand monitor installations.

The latest developments in sand monitoring systems are presented, including the introduction of a retrofit system that can be installed without any disturbance to production. The paper also discusses the probable future of sand management and monitoring for subsea installations.
The Challenges of Predicting Commingled Production of Rich and Dry Gas Reservoirs of the Saih Rawl Field, Oman
Authors: Al-Marhoon N. , Al-Shidhani S.
Published: December 2007

The Saih Rawl field (SR) is the biggest gas field in Oman, containing condensate rich gas in the Barik sandstone reservoir and dry gas in the deeper Miqrat sandstone reservoir. Production to date was mostly from the Barik reservoir, at which most wells are completed, resulting in the reservoir pressure dropped to a current average of 260 to 470 bar form the initial pressure of 513 bar. Furthermore the layered nature of the reservoirs and the varying hydraulic fracturing of the different units, production from the various units differed significantly resulting in significant vertical differential depletion of the reservoir. The field's CGR (Condensate Gas Ratio) of the Barik reservoir has dropped from 480 m3/MMm3 to 300 m3/MMm3 as a consequence of liquid drop out resulting the Barik reservoir pressure dropping to below the dew point pressure, and the increasing dry gas production from Miqrat reservoir through commingled production from some of the wells.

Well performance in the Saih Rawl field is affected by the flow impairment caused by the condensate dropout, the quality of the placed hydraulic fractures in terms of their efficiency and geometry, and completion type, single reservoir or commingled in the two reservoirs of Barik and Miqrat. This makes predicting well performance a very complex undertaking.

The limited worldwide experience in developing tight gas-condnesate reservoirs possed a genuine challenge for the initial development planning of this field in the mid-1990s. In particular the prediction of the long term production behaviour.

Production of gas/condensate wells in tight reservoirs with liquid drop-out is still one of the most challenging subjects in reservoir engineering today. The Saih Rawl field provides one of the first sets of comprehensive data on this phenomenon. The paper reviews actual reservoir performance in the Saih Rawl field over the first 40 months of its production life. For example, high well declines have been observed (upto 50% per annum), the effect of fluid mixture of the rich and dry gas, resulting from the commingled production, the potential cross-flow of the dry gas to the rich gas as was indicated by condensate production and the well capacity. Dynamic models, calibrated by historic production data, are used to assess these effects and to predict future production performance.
Improved Design & Modification of System Results in Efficient Gas Processing in Offshore Gas Field - A Case History
Authors: Shankar Ravi , Kumar Adesh , Gupta V. P.
Published: December 2007

BXY field is the largest gas field of India, located in offshore, 80 km from Mumbai city. The field is currently producing about 32.5 MMscmd sour gas using two process complexes BXA & BXB. The field was put on production in September 1988, with initial gas production of about 2 MMscmd. The field attained a gas production of 10 MMscmd during 1994 and this was the period when some operational problems were observed at one of the process complexes i.e. BXA.

The sour gas processing at BXA consists of cooling of well stream fluids in shell-tube type well stream coolers, three phase separation of well fluid and finally transportation of gas & condensate to shore terminal at a distance of about 235 km. Initially each complex was designed for lesser capacity which was upgraded to 15 MMscmd in 1995-96 after progression of field development. No problem was observed in BXB complex. However, in BXA complex, the gas processing temperature exceeded the desired temperature of 43°C. This resulted in rising trend of moisture content in sales gas, high consumption of TEG (2-3 times more than normal value) in dehydration unit and increased load on operational staff for monitoring. Frequent failures of pipe & fittings of gas cooling system were observed. Well stream coolers had problem of air locking & cooling water flow across coolers came down to half quantity. Overall, severe operational problems were observed in the plant.

An in-house analysis was carried out to resolve these problems. The analysis of total processing system viz. gas cooling system, gas dehydration system, condensate stabilization system was made. Based on analysis, it was found that gas cooling water system is the bottleneck. The various components including material of construction of various equipment of this unit were analyzed and causes of operational problems resolved. A new cooling water system known as ‘cooling water segregation system’ was conceived, designed and installed at BXA complex & other suitable measures undertaken. These efforts streamlined the operating conditions of plant and are now processing 16.5 MMscmd gas without any problem.

The present paper describes stepwise identification of problems, design, review, installation of newly designed system and other issues to resolve the operational problem in this major processing complex. The improved design on implementation resulted in smooth operations in the plant and is working since then without any problem.
Strategies to Mitigate Corrosion Caused Due to H2S in Wells and Well Fluid Lines of Mumbai Offshore, India
Authors: Mali P. V. , Khanra Amit , Sagar P. K. , Meshram P. N. , Singh R. K. , Johari Anil
Published: December 2007

Present work focuses on mitigation strategies adopted to avoid corrosion due to H2S. This can be best achieved by reducing H2S generation to the maximum possible extent. The work pertains to 135 wells and 26 well-fluid lines located in Mumbai Offshore, India. Reservoir souring and injection water breakthrough in oil wells are prime sources for H2S generation. Injection water treatment with biocides, pigging and biocide treatment for well-fluid lines and periodic monitoring of H2S levels, are found to be effective measures for reducing H2S generation.
Single Well Tests to determine the Efficiency of Alkaline-Surfactant Injection in a highly Oil-Wet Limestone Reservoir
Authors: Zubari Hisham K. , Sivakumar V. C. Babu
Published: December 2007

The Mauddud carbonate reservoir is the main oil producer in Bahrain oilfield that has been undergoing crestal gas injection with natural aquifer support at the flanks. It has been producing since 1932 and currently in a very mature stage. Due to its rocks wettability characteristics (preferentially oil-wet nature), the residual oil left behind gas and water fronts range from 20-70%. One of the potential options to recover portion of this residual oil is through Chemical Flooding possibly Alkaline-Surfactant-Polymer (ASP) flood. A project was hence initiated to investigate its technical and economical feasibility. It was decided to carry out field experiments to gauge the reservoir response through well-bore treatments before proceeding with a full-scale study and field pilot implementation. Initial field-testing on single-well huff-and-puff basis with experimental recipes provides sufficient positive indications for the project to proceed.

The results of these initial tests are presented in this paper.
Effect of Gravity on Waterflooding Performance of Stratified Reservoirs
Authors: El-Khatib Noaman A. F.
Published: December 2007

In this paper, an analytical solution is developed for waterflooding performance of stratified reservoirs with gravitational (bouncy) effects between adjacent layers. The ordering of layers is kept unchanged as obtained from core analysis or well logging or as randomly sampled from a specified distribution (usually a log-normal). Differential equations are obtained and solved for the rate of advance of the displacement fronts in two or three successive layers of decreasing permeability. The locations of the displacement fronts are used to obtain expressions for the time of water breakthrough in the successive layers and oil recovery factor and water cut at the time of breakthrough in the different layers.

The effect of mobility ratio, gravity number and the Dykstra-Parsons coefficient of permeability variation on the performance are investigated. Expressions for pseudo relative permeabilities are also derived. Results from the developed model were compared with those from conventional models that neglect gravity effecys.
Neural Network Prediction Model of Miscible Displacements in Heterogeneous Reservoirs
Authors: Gharbi Ridha B. C.
Published: December 2007

Understanding and predicting the performance of solvent drives and remediation of contaminated aquifers in heterogeneous reservoirs is of great importance to the petroleum and environmental industries. In this paper, a general method to scale flow through heterogeneous reservoirs is presented for a miscible displacement of oil by a solvent. Results show that scaling miscible displacements in a two-dimensional, heterogeneous, anisotropic vertical cross section requires the matching of thirteen dimensionless scaling groups. These groups were derived using a general procedure of inspectional analysis. A detailed numerical sensitivity study was performed to reveal the relationship between the scaling groups and the fractional oil recovery of miscible displacements in heterogeneous reservoirs. This relationship was then mapped using an artificial neural network, which can be used as a quick prediction tool for the fractional oil recovery for any combinations of the scaling groups, thus eliminating the need for the expensive fine-mesh simulations. These results have potential applications in modeling miscible displacements and in the scaling of laboratory displacements to field conditions.
Wettability and Relative Permeability of Lower Cretaceous Carbonate Rock Reservoir, Saudi Arabia
Authors: Okasha T. M. , Funk J. J. , Al-Enezi S. M.
Published: December 2007

Results and discussions in this paper relate to a Lower Cretaceous carbonate reservoir located in southeastern Saudi Arabia. It is a heterogeneous carbonate formation with various facies due to diagenetic alteration of the original rock fabric. The reservoir is large and prolific with mixed-wet characteristics. Because of the economic importance and variety of oil-recovery mechanisms operative or possible in the reservoir, the multi-phase recovery behavior has been extensively studied. Also, various wettability tests were carried out using Amott and USBM methods.

This paper describes the variation in wettability and relative permeability of Lower Cretaceous carbonate reservoir and the multi-phase simulations of the experimental results. It shows that measurements are consistent with recent theories of the relationship between water saturation, relative permeability, and wettability as described by Jadhunadan and Morrow, 1991.1 However, the results indicate that the wettability of the reservoir changes from water-wet low on structure near the oil/water contact to intermediate and/or oil-wet behavior higher on structure. Oil-wetting character increases towards the top of oil column and is correlated to decreasing water saturation. The results revealed that changes in wettability are accompanied by changes in waterflood efficiency and facies of deposition.
SHAYBAH-220: A Maximum Reservoir Contact (MRC) Well and Its Implications for Developing Tight Facies Reservoirs
Authors: Saleri N. G. , Salamy S. P. , Mubarak H. K. , Sadler R. K. , Dossary A. S. , Muraikhi A. J.
Published: December 2007

This paper presents drilling, completion, well performance, and reservoir characterization results of a recently-drilled Maximum Reservoir Contact (MRC) well in the Shaybah Field with a total of eight laterals and an aggregate reservoir contact of 12.3 kms (7.6 miles). The well was drilled as part of a pilot program to evaluate both the practical challenges and the reservoir performance impact of MRC wells.

The results to date on three MRC wells in Shaybah indicate significant gains in well productivities as well as reductions in unit development costs. A useful by-product of MRC drilling is the enhancement achieved in reservoir characterization. These benefits point to MRC wells as disruptive technologies (DTs)1,2 which have far reaching implications for developing tight-facies reservoirs.
Innovative Completion Technology and Contingency Planning Simplify Al-Khalij Completions and Reduce Installation Costs
Authors: Giusti F. Duke , Leschi Pierre
Published: December 2007

Enhanced simplicity and reliability are critical in offshore development because of the increased intervention cost compared to onshore services. Recently, TotalFinaElf E&P Qatar completed 15 wells in the Al-Khalij Field, 135 km northeast of Doha, Qatar. Because of the deviation at which they wished to set the packers, the operator needed a completion method that would eliminate slickline intervention. After considering many completion options, the following equipment was chosen: An interventionless plugging device that would allow testing of the entire tubing string without setting the hydraulic packer, during running of the completion, and would allow setting of the hydraulic packer, when on depth, without slickline or coiled-tubing intervention.Punch-to-release injection packers with the reliability of permanent packers that would provide capability to retrieve the entire completion without conducting costly and potentially damaging milling operations.ESP packers that could be reset to allow repairs at the wellhead without pulling the tubing string to replace the packer.Nippleless lock technology to keep the required number of landing nipples to a minimum while providing the utility to place flow-control devices anywhere in the completion string.

TotalFinaElf Qatar employed the above philosophies in completing their wells. By using interventionless completion philosophies and innovative installation methods, the client saved approximately 16 hours of rig time per well and a minimum of 4 slickline runs into each well to run/retrieve the intervention tools. The equipment also allowed testing of the tubing and provided a barrier while installing the tree. Finally, in addition to reducing cost, the elimination of intervention operations reduced risks to the safety of the personnel, the environment, the equipment, and the well bore.

Based on the success of these operations, TFE is planning to use the same completion design to complete a minimum of 10 wells in Phase 3 of the Al-Khalij project.

This completion system can be used in applications that would benefit from a completion deployment without well intervention to set plugs, test tubing or set a packer.
Upscaling and 3D Streamline Screening of Several Multi-Million Cell Earth Models for Flow Simulation
Authors: Samantray Ajay K. , Dashti Qasem M. , Ma Eddie D. C. , Kumar Pradeep S.
Published: December 2007

Nine multi-million cell geostatistical earth models of Marrat reservoir in Magwa field of Kuwait were upscaled for streamline screening in FRONTSIM and flow simulation using ECLIPSE.

The scale-up strategy consisted of (1) maintaining square areal blocks over the oil column, (2) upscaling to the largest areal block size (200m x 200m) compatible with 125 acre well spacing, (3) upscaling to less than a million grid blocks for FRONTSIM streamline screening, and (4) upscaling to less than 250,000 grid blocks for ECLIPSE flow simulation. GOCAD-SCP program was utilized for scale-up. SCP employs a single-phase flow-based process for upscaling non-uniform 3D grids. Several iterations of scale-up were made to optimize the result.

Sensitivity tests suggest that a uniform scaled-up grid overestimates breakthrough time compared to the fine model and the post-breakthrough fractional flow also remains higher than the fine model. However, preserving high flow rate layers in a non-uniform scaled-up model was key to match the front tracking behavior of the fine model. The scaled-up model was coarsened in areas of low average layer flow since less refinement is needed in these areas to still match the flow behavior of the fine model. The final ratio of pre- to post-scaleup grid sizes was 6:1 for FRONTSIM, and 21:1 for ECLIPSE.

Several checks were made to verify the accuracy of scale-up. These include comparison of pre- and post-scaleup fractional flow curves in terms of break through time and post-break through curve shape, cross-sectional permeabilities, global porosity histograms, porosity-permeability clouds, visual comparison of heterogeneity, and finally earth model and scaled-up volumetrics.

The scaled-up models were screened using FRONTSIM 3D streamline technique. The results helped in bracketing the flow behavior of different earth models and evaluating the model that better tracks the historical performance data. By initiating the full-field history matching process with the geologic model that most closely matched the field performance in the screening stage, the amount of history matching was minimized and the time and effort required reduced. The application of unrealistic changes to the geologic model in order to match production history was also avoided.

The study suggests that single realizations of "best guess" geostatistical models are not guaranteed to always offer the best history match and performance prediction. Multiple earth models must be built to capture the range of heterogeneity and assess their impact on reservoir flow behavior.
Bahrain Field – An Integrated Simulation Study of 15 Reservoirs
Authors: Kumar K. , Abdulwahab Ayda E. , Al-Muftah Ali , Alcobia Victor , Carvalho Alvaro
Published: December 2007

The Bahrain field is an asymmetrical anticline trending in the North-South direction. The field was discovered in 1932. The field is a multi-stack carbonate and sandstone reservoirs most of them oil bearing. The fluids range from tarry oil in Aruma zone to dry gas in the Khuff zones. The geology of the field is extremely complex with a large number of faults especially in the Wasia group formations, which contain the major oil reservoirs of the Bahrain field. These reservoirs are at different stages of the production cycle.

Following a 3-D seismic acquisition campaign in the year 2000, Bapco took up an integrated study to develop numerical models as the main tool to assess alternative production mechanisms. This integrated study faced a significant number of challenges, which had to be overcome with innovative ideas.

The challenges included representing communication between reservoirs through faults, complex rock and fluid distribution from heavy oil to gas condensate, gas injection, aquifer encroachment and fracture intensity. Although the hardware required for handling the large simulation models was meticulously selected based on benchmark data of the various machines, the geological complexities posed serious problems while running the simulation models.

This paper describes the challenges faced by the joint Bapco-CGG team and the approaches adopted to overcome these challenges.
Experience on the Survey & Repair Methods of Wear Problem on High Pressure Gas Transmission Pipelines
Authors: Al-Dossary Bader
Published: December 2007

Over time pipelines in the field, transporting high-pressure gas, have exhibited severe external wear at support locations, especially near bends, due to expansion/contraction with respect to climatic conditions.

This paper describes on-stream inspection survey techniques and the subsequent repair/inspection methods carried out, to ensure that pipeline integrity is maintained. The first gas transmission lines were constructed around 30 years ago, meeting the code requirements of ASME/ANSI B31.8, with an operating pressure of approximately 1050 psi. In July 1998, at one location, a 12" gas transmission line leaked due to external wear of the pipe at its point contact with a transverse support.

This paper also focuses on the significance of design location class, field investigation, corrective & preventive measures, repair & acceptance methods.
Investigation of Causes of Tight Emulsions in Gas Oil Separation Plants
Authors: Al-Ghamdi Abdullah , Kokal Sunil
Published: December 2007

Mubarraz area which is located in the center of the giant Ghawar field in Saudi Arabia has several wet crude handling facilities referred to as gas oil separating plants or GOSPs. These GOSPs process Arabian Light crude and their primary function is to separate oil, water and gas. In the past it has been observed that the usage of demulsifier varies from GOSP to GOSP. Some GOSPs, like GOSP-2, consume higher dosage of demulsifier compared to the other GOSPs. At the request of operations engineering personnel, and in partnership with them, a research study was initiated to investigate the causes of variable demulsifier usage in GOSPs, factors that stabilize these emulsions, and to evaluate the relative performance of demulsifiers. The primary objective of this study was to optimize the use of demulsifier in GOSPs while meeting crude and water specifications.

This paper provides results of an investigative study conducted to determine the causes of tight emulsions in GOSPs. The emulsions from different GOSPs were characterized in terms of their tightness using Emulsion Separation Index1. The study has also determined the causes of emulsion tightness in these GOSPs. These include crude oil temperature at the GOSP, percentage of wells squeezed with scale inhibitor, and overall GOSP watercuts. Based on these results several recommendations have been made to optimize demulsifier usage, ways to reduce emulsion tightness in Mubarraz field and test promising demulsifiers that should result in cost savings. The paper describes the partnership with operations and production engineering to optimize demulsifier usage at the GOSPs.