bluuebunny/crossref_metadata_2025 huggingface dataset:
Direct Geostatistical Simulation With Multiscale Well, Seismic, and Production Data
Authors: Tran Thomas T. , Deutsch Clayton V. , Xie Yulong
Published: December 2007

Multiple realizations of facies, porosity, and permeability are used for better representation of reservoir heterogeneity for more accurate performance forecasting and uncertainty assessment. These geostatistical realizations must reproduce all available data to be reliable. The available well, seismic, and production data are at different scales and must be linked to the reservoir modeling scale. The most common geostatistical simulation algorithms call for a Gaussian or normal transformation. It is not possible to merge the data types after this non-linear transformation. This has led to development of "Direct" approaches for simulation and data integration.

Considering the variables without transformation ensures reproduction of the different data and the prescribed covariance or variogram model; however, until now, the resulting global histogram of the simulated realizations is not reproduced. The problem is that there is no theory that specifies the shape of the conditional distributions. The mean and variance are determined from the well-known normal or simple kriging equations; however, theory has not existed to specify the shape of the conditional distributions. A number of ad-hoc solutions have been proposed, but they violate the data and artificially reduce the modeled space of uncertainty.

This paper develops a theory for determination of the required distribution shapes and reproduction of the global histogram. The results have significant theoretical and practical consequences. Data from multiple sources and scales can be directly reproduced in reservoir models with no need for transformation. There is no need for ad-hoc post-processing transformation or correction schemes. Several applications with synthetic data are shown to illustrate the technique.
A Joint Industry Project to Assess Circulating Temperatures in Deepwater Wells
Authors: Ward M. , Granberry V. , Campos G. , Rausis M. , Sledz M. , Weber L. , Guillot D. , Naziri I. , Romero J.
Published: December 2007

Drilling oil wells offshore in water depths exceeding 1000 m is not uncommon in many parts of the world. These conditions present a number of challenges for successfully cementing even the shallowest strings. A major challenge is predicting the temperature to which the cementing fluid(s) will be submitted during and after placement so that laboratory procedures can best simulate the actual situation. What sounds like an easy task for the majority of land wells or offshore wells with shallow water depths turns out to be much more difficult for deepwater wells. This is due in particular to inverse temperature gradients across the sea and convective thermal exchanges between the sea and the fluids in the riser and/or drill pipe.

To better understand the phenomena involved, a series of temperature measurements was made as part of a joint industry project. The primary objective of these measurements was specifically to monitor the cooling effect of the sea through the measurement of the fluid temperature at the mud line depth. All temperature data were measured by a sensor deployed inside the bottomhole assembly while circulating or drilling. This method was selected for its low cost and lack of interference with drilling operations. Data were collected in the Gulf of Mexico, Brazil, Indonesia and West Africa with an average water depth of 1200 m.

A summary of the temperature measurements is presented. Comparison is also made with the predictions of a numerical simulator. The detailed interpretation of these data gathered pinpoints the importance of correctly accounting for the exact temperature profile in the sea as well as the velocity of sea currents versus depth. The outcome of this study helps to define better cement slurry testing procedures for deepwater applications. As a result the technology that is best suited for these specific conditions can be selected on a more rigorous technical basis.
New Applications for 2 1/8" Well Tractor inside 5" Drill Pipe
Authors: Stragiotti Stephen , Skeie Terje , Krüger Christian
Published: December 2007

This paper describes the use of Well Tractor® technology to convey services for recovery of stuck drillpipe in circumstances where conventional methods were considered economically or technically unfeasible.

In the first case, the drillpipe became stuck while running in and circulation was subsequently lost. After 100 jarring cycles were performed it was decided to attempt a fishing operation using the 2 1/8" Well Tractor enabling the retrieval of the radioactive logging source. The retrieval tool was deployed on Well Tractor, which enabled the radioactive source to be successfully recovered from the bottom hole assembly (BHA). The drillpipe was subsequently backed-off using Well Tractor to convey the explosives.

In the second case, drilling losses to the formation were experienced and it was decided to pump lost circulation material. However, during pumping the drillpipe plugged up completely. At the same time flow was recorded on the annulus side and the drilling BOP annular preventer was closed with subsequent pressure build-up below. A 2 1/8" Well Tractor was successfully run inside the DP to first gauge and subsequently punch holes in the drillpipe to open for circulation, thereby allowing pumping of heavy mud and regaining well control.
Assessment of Risk and Uncertainty for Field Developments: Integrating Reservoir and Drilling Expertise
Authors: Irrgang R. , Irrgang H. , Kravis S. , Irrgang S. , Thonhauser G. , Wrightstone A. , Nakagawa E. , Agawani M. , Lollback P. , Gabler T. , Maidla E.
Published: December 2007

This paper describes FieldRisk, a knowledge based drilling system combined with a probabilistic cost and risk assessment software tool for integrated evaluation of field development options. The project uses field data and case studies and includes a database of drilling data from Australia, the Middle East, Europe, and the USA. Knowledge is captured from diverse sources including industry experts, company reports, and published papers using automated information extraction software. Lessons learned in previous field developments can be recycled and applied to similar situations to give a more accurate estimate of costs and risks. Risk, uncertainty and company learning curves are estimated using statistics from past data with allowance for dependencies between events. FieldRisk supports integration of drilling, reservoir and development risks which is a key need for realistic evaluation of offshore field development scenarios. For example, a horizontal well may offer higher production rates, but with a higher risk of hole instability and increased cost of reservoir monitoring and recompletion. Modelling the system in its coupled state can produce a global, life of field optimisation. The tool can use analogous well data from the database for a quick look at costs of proposed new acreage where company offset data may not be available. Multi-target 3D well trajectories can be designed automatically to estimate drilling costs by clicking on a plan view of the field and selecting target depths. Options for drilling and well sequencing, completions, facilities, reservoir risks, reliability of supply and economic considerations can be evaluated in parallel. The tool allows different levels of granularity. Planners can get quick cost estimates, while the asset team can access more detailed information from the knowledge base or view graphically summarised supporting data from similar wells.
Efforts to Persevere a Risk Assessment/Integrity Assurance for its Aged Hydrocarbon Transfer Pipelines
Authors: Kandil Mohamed Essam
Published: December 2007

It is GUPCO's policy to protect against oil pollution and to provide a hazardous free environment for operations within our company.

Maintaining the integrity of oil, gas and water transfer pipelines represents a continuous challenge in GUPCO. It was realized that a pipeline integrity assurance plan could be achieved through the application of a tailored risk assessment program. The key issues of this program which required a reassessment were identified as educating pipeline operators to understand and apply the procedures set out in our management of change (MOC), hazards identification (HAZID), hazards and operability study (HAZOP) and environment impact assessment (EIA) techniques.

As a result, GUPCO has succeeded in making progress towards developing a risk assessment program that provides assurance to help manage pipeline failures, permit adequate environment protection, achieve safe operation and comply with both company and governmental regulations.
Very Thick Crude Emulsions: A Field Case Study of a Unique Crude Production Problem
Authors: Kokal Sunil , Al-Yousif Ali , Meeranpillai N. S. , Al-Awaisi Mohammad
Published: December 2007

This paper presents the results of a unique emulsion and sludge problem in one of the largest offshore oil fields in the world. The problem is related to heavy emulsion sludge deposition in the crude handling facilities. Very viscous emulsions containing 70-90% water were encountered in the offshore facilities where they were plugging up over 50% of the effective separator volume. As there is no bottom water drain at these crude handling facilities, the wet crude forms a very tight, complex emulsion that settles down in the equipment. This problem is anticipated to increase in the future as the water production increases in the field.

A comprehensive study was initiated to diagnose and remedy the problem. Recommendations were made early on to conduct field trials by injecting a demulsifier at the wet crude handling facilities to control the sludge problem. Field trials were conducted at three offshore facilities. Samples were collected before and during demulsifier injection. A new method recently developed for testing emulsions was used to evaluate the removal of the thick emulsions. These field trials were successful and the emulsion/sludge problem has been brought under control. The sludge has been removed and the crude handling facilities are running with minimal demulsifier injection. This paper will describe the research work including a new method to test emulsions, comprehensive results from field trials, and highlight the teamwork between the Research Center and field personnel in successfully solving and controlling an operational problem.
Advanced Interpretation of Venturi Meter Measurements in Multiphase Flow
Authors: Lindsay I , Stimpson B , Corlett A
Published: December 2007

The Venturi meter is commonly used in combination with other sensors for the measurement of gas fraction and water cut as part of a multiphase flow meter system for the measurement of oil, water and gas flowrates. The Venturi differential pressure signals are generally interpreted using empirical corrections to a momentum equation to give a solution for volumetric flowrate.

In this project the use of advanced processing techniques and neural networks have been used to examine the potential improvement in measurement performance which may be obtained from a system incorporating a standard Venturi tube in combination with a gamma densitometer. The data is preprocessed before being applied to a neural network using simple statistical methods combined with some signal processing techniques.

It has been found that this neural network solution performs extremely well when only predicting the gas and liquid phases. Poorer performance was registered when trying to predict all three phases, indicating the need for a water cut sensor.
Yme Marginal Field, 12 km Subsea Gas Lift Experience
Authors: Øverland Alf Midtbø , Ramstad Helge J.
Published: December 2007

Gas lift wells producing from a subsea template placed 12 km away from the processing facilities is known to be very challenging. Long pipelines give large volumes of gas and fluid which may influence each other, causing slugging or pressure variations in production pipelines and pressure fluctuations in the gas lift line. This again creates variations in rates and pressure into the process plant. Gas lift is the preferred artificial lifting method in subsea completed wells, due to the roboustness.The Yme Beta Øst subsea wells were put on production in the summer of 1996. Following a period of natural production the gas lift was started March 97. Immediately after start up of the gas lift heavy slugging in the system, both subsea and in process units was observed. As a result of the slugging the process was frequently shut down due to the pressure and rate variations. To reduce the slugging the wells were choked back, leading to reduced production. The slugging was investigated and the reason for the slugging was found to be in the production pipelines. The varying pipeline pressure influenced the gas lift system in the wells. In order to reduce this, a new gas lift design was carried out and new gas lift valves installed in one of the Yme Beta Øst wells and later both Beta Vest wells.
Interpretational Complexities and Operational Complications Affecting Pressure Transient Analysis in Zuluf Field, Saudi Arabia
Authors: Al-Ghamdi Abdulla H. , Al-Zayer Rayed M. , Al-Samin Isa A. , Al-Gattan Abdulaziz A.
Published: December 2007

The study of pressure transient testing in Zuluf field was initially undertaken to estimate important well and reservoir flow parameters and characterize heterogeneities in the Khafji reservoir. However, during the course of interpretation, numerous engineering complexities were encountered due to the nature of well behavior and reservoir petrophysics. Furthermore, many operational complications resulted in low quality data that negatively influenced the accuracy of the analysis. Interpretational difficulties were caused by complexity in determining net reservoir thickness and wide variation in fluid PVT properties. Operational complications, on the other hand, were caused by wellbore phenomena such as gas slugging, gas humping and phase segregation that affected the accuracy of rate measurement and led to the masking of the actual reservoir response.

These difficulties encountered have led us to take a global diagnostic perspective at the overall well testing practices in Zuluf field with the aim of identifying their causes in order to take the appropriate remedial actions. In light of the outcome of this study, recommendations are made to improve quality of test data by modifying current testing procedure and/or suggesting new alternatives1. Engineering recommendations are also presented in order to standardize the selection of net pay thickness and facilitate the well test interpretation process. This paper highlights findings, results and recommendations of pressure transient analysis study that was conducted in Zuluf field.
Mississippi Canyon 348: Some Reservoir Engineering Considerations Regarding Development of a Deepwater Biogenic Gas Accumulation
Authors: Edman J. D. , Jameson E. W. , Perkins T. M. , Guthrie G. E.
Published: December 2007

Mississippi Canyon 348 (Camden Hills) is a recently discovered biogenic gas field in the deep-water (7200 ft) Gulf of Mexico. The gas in this field is stratigraphically and structurally trapped in a multi-story, distal turbidite channel sand complex. Although considerable work is published on biogenic gas that has been generated and trapped in shelf and deltaic depositional systems, little is understood about biogenic gas accumulations in distal, deep-water, low net sand depositional settings such as this. Given the water depth, a number of economic concerns regarding the reservoir arose during evaluation of the development and delineation wells. First, there was concern about the possible presence of wax and condensate in the reservoir gas. Detailed monitoring of the synthetic drilling mud used in the wells in conjunction with rigorous gas chromatographic analysis of the drilling mud and reservoir hydrocarbons revealed that both condensate and wax are associated with the biogenic gas.

Another engineering and economic concern in this low net sand system was the possibility of reservoir compartmentalization. Geochemical analyses of the methane revealed it to be very uniform and homogenous with respect to both its’ composition and carbon isotopic signature over a vertical interval of at least 4000 ft. However, differences in isotopic signature of immature, indigenous thermogenic gases in discovery well MDT tests demonstrated vertical compartmentalization of the various sands. Later, in the delineation well, similar gas analyses showed the main reservoir sand to be in fluid communication laterally. Early recognition of compartmentalization and the presence of wax and condensate in the reservoirs enabled Marathon to factor these considerations into the field development economics.
An Integrated Pipe Network Model for Simulation of Highly Fractured Reservoirs
Authors: Zhan Lang , Ershaghi Iraj
Published: December 2007

The Monterey Formation, a very prolific reservoir rock, exhibits unique fracture structures where fault zones and other highly brecciated intervals serve as large conduits for fluid movement. Modeling of a network for effective tracking of oil-water contact and rapid subsidence of the invaded water requires new thinking on the modeling process. In this work, we propose a novel integrated pipe-network model (PNM) for simulation of highly fractured reservoirs. It consists of constructing a regular or irregular pipe-network in 2D or 3D space according to major fracture distribution and orientation in reservoirs. Pipe network is the channel for fluid flow, where Darcy's law is applied directly. Micro-fractures and possible matrix in the formation serve as reservoir storage elements at pipe network junctions, at which mass balances are established. The major benefits of the new technique are simplicity in mathematical formulation and superior ability to adapt to fracture distributions. An example is included to compare the result of the proposed pipe network simulator with that of a traditional dual porosity simulator.
The Outlook For U.S. LNG Imports
Authors: Hay Nelson E.
Published: December 2007

Hay, Nelson E., Manager, Policy Analysis American Gas Association

In recent months the desirability of providing increased gas supplies from importation of liquefied natural gas (LNG) has become a major focus of legislative and regulatory attention in Washington. As a relatively "new" energy source, at least in terms of public awareness, LNG has become the focal point for many of the larger issues of the energy policy debate.

This paper will, first, address the role and advantages of LNG importation, second, review the existing and proposed LNG import projects and, finally, summarize the proposed LNG import projects and, finally, summarize the current federal LNG legislative and policy situation.

Introduction

Natural gas currently provides a major contribution to U.S. energy supplies, accounting for almost 30% of all energy consumed in the U.S. in 1976. Gas is used in over half of the nation's residences and commercial establishments, serving over 44 million customers. American industry also depends heavily on gas, which accounts for over 40% of all domestic industrial energy consumption. Moreover, the nation has a major financial commitment to natural gas, with a total utility industry and consumer equipment investment estimated to exceed $100 billion. Half of this investment is represented by almost 1 million miles of underground gas pipeline and main throughout the U.S.

While there are at least 35 years of conventional U.S. natural gas supplies remaining at current levels of use, demand for gas is growing at the same time that gas is becoming more difficult to find and produce. More realistic federal regulatory policies allowing new gas price equivalency with alternative fuels would assure that U.S. natural gas production could be sustained at current levels for an additional 15 to 20 years, but it is clear that sometime after the early 1990's domestic production of conventional gas will begin to decline. This decline, coupled with continued growth in total U.S. energy demand in spite of vigorous conservation efforts, means new sources of gas will be needed to meet future U.S. needs.
Invert Gravel Pack Carrier Fluid
Authors: Donaldson A. , Vitthal Sanjay , Welch J. C. , Nguyen P. D.
Published: December 2007

Invert and all oil/synthetic drilling fluids are being used in high-angle wells, which can be excellent candidates for gravel-packing. This practice has led to a need for a complete fluid system to drill and gravel-pack the reservoir. The new system should also be completely compatible with the fluids and provide the highest degree of formation damage protection.

The Invert Gravel Pack Fluid (IGPF) system can provide an option for carrier fluid for gravel-packing payzone intervals drilled with invert (oil- or synthetic-based) drilling fluids. The primary advantage is the compatibility of the drilling fluid and the gravel-pack fluid. This compatibility helps maintain the highest degree of lubricity of the wellbore, which can aid in the operation of the gravel-pack assembly while providing the highest degree of formation inhibition. The fluid is free of any solids for density, yet, based on current design, provides an invert system weighing to at least 12.2 ppg.

To validate the new system, design work was first conducted in Baroid's Houston Research and Development lab. Additional testing and validation was done at Westport Laboratories and Halliburton's laboratory in Duncan, Oklahoma. Testing consisted of regained permeability, filter-cake erodability, and testing on a gravel-pack simulator loop to help determine the effectiveness of the fluid as a gravel carrier.

This paper describes the testing protocol and fluid design. It also describes the fluid properties to help prove the effectiveness of the fluid as a carrier fluid and shows a relationship with the properties of conventional brines used as carrier fluids.
Development and Use of a Through-Tubing Aluminum Cement Basket
Authors: Lam J. S. , Lee J. R. , Hands N. , Nelson R. , Murphy T.
Published: December 2007

An ingenious and inexpensive removable through-tubing cement basket has been constructed for use in open or cased hole and highly corrosive environments. While the basket was designed specifically for use in deep sour gas wells with sulphur deposition problems, it can be used in any zonal isolation application. A conventional inflatable through-tubing bridge plug can be used in sour service, but its elastomeric components make the plug vulnerable in the presence of sulphur solvents and amine based corrosion inhibitors. The cement basket is constructed from 100% aluminum, which eliminates the problems associated with the elastomeric materials and assures complete removal with acid, thus leaving no debris in the well.

In June 2000, the cement basket was successfully deployed in a deep, sour, horizontal gas well. The 54mm OD basket was run through the tapered 89/73mm OD tubing string before being expanded in the 127mm OD production liner and capped with 4 metres of calcium carbonate chips and 10 metres of cement to provide the pressure integrity. Once cemented, the basket became a plug providing well control for workover operations and a barrier preventing fluid and debris loss to the formation. Subsequently, the permanent packer was milled and retrieved, enabling a new packer and larger tubing to be installed. The aluminum basket with the carbonate and cement cap was successfully milled out using coiled tubing in less than three hours. A small quantity of acid was used to remove any debris from the cement basket and cement sheath from the liner wall.

While the cement basket is a new development, it is deployed using conventional, field proven equipment. It is also simpler and offers the potential for cheaper solutions than a conventional expandable bridge plug. With the experience gained, the next challenge is to build a 42 mm O.D. plug to be set inside 178mm OD casing, which will be more universally applicable for wells in Western Canada and around the World.
Precipitation During the Acidizing of a HT/HP Illitic Sandstone Reservoir in Eastern Saudi Arabia: A Laboratory Study
Authors: Thomas R. L. , Nasr-El-Din H. A. , Lynn J. D. , Mehta S. , Zaidi S. R.
Published: December 2007

Field results indicate that the Jauf reservoir, a deep, high temperature illitic sandstone, is sensitive to conventional mud acid treatments. As a result, an extensive study was performed to better understand the problem.

The focus of this paper is on core flow tests using various inorganic and organic preflushes and mud acid (HCl – HF) systems. Interpretations of the core tests results are supported by chemical, XRD, SEM, and Thin Section analyses. A detailed description of the mineralogy of cores prior to and following an acid treatment is presented with emphasis on precipitation of reaction products, fines migration and other potential damage mechanisms.

Chemical analyses indicated that the HCl preflush extracted the majority of the aluminum during a conventional mud acid treatment. As a result, the Si/Al ratio during the subsequent mud acid stage is a false indicator of hydrated silica precipitation. Additionally, precipitation can occur in acid effluent collected during a core test once the fluid cools to ambient temperature. This results in an erroneous Si concentration and impacts numerous calculations and "conclusions" i.e., reaction kinetics, amount of silica precipitation, etc. The same analogy applies to flowback samples that are used to postulate various downhole phenomena. Although potassium hexafluosilicate was present in core effluents, it was not present in the cores based upon XRD, SEM, and Thin Section examination. Potassium hexafluosilicate was identified as two distinct crystal structures i.e., cubic and pyramidal.

SEM examination showed that most cores exhibited severe alteration of illite and chlorite to yield a significant quantify of clay residue including fines. The residue, severely degraded potassium feldspar (microcline) and quartz fines created formation damage subsequent to treatments with 12 wt% HCl – 3 wt% HF mud acid.

This paper supports the literature in some cases yet spotlights some possible flaws in our understanding of sandstone acidizing.
A New Statistical Method for Interpreting Production Logs
Authors: Li H. , Zhu D. , Lake L. W. , Hill A. D.
Published: December 2007

Production logging suites often consist of some redundant measurements. For example, water holdup in wells producing oil and water is commonly measured by both fluid density and fluid capacitance logs. Each of these logs will contain some error, the level of which is likely different for each log. We present a statistical method for combining multiple log measurements so that the overall error in the interpreted parameter is minimized. The method is applied to multiple holdup logs and to interpreting multiple passes of a spinner flowmeter. The new technique yields the statistically most accurate interpretation and also provides an estimate of the statistical error involved. Synthetic logs are used to prove that the method minimizes the error in the interpreted flow profiles. Field examples of multiphase log suites and multipass spinner flowmeter logs illustrate the applications of the new method.
The Cook Project-Unlocking Potential
Authors: Hill Nigel
Published: December 2007

Enterprise Oil became the Operator of the Cook Field in 1990. A single well had been drilled into the reservoir in 1983, and new 3D seismic data had been shot in 1991. Since becoming Operator, Enterprise Oil reviewed the development options for the Field, until it identified an opportunity in 1998 to unlock the reserves using available ullage in the Shell Expro Anasuria FPSO.

This presentation describes the Field, the potential development options, and the rationalisation in facilities architecture necessary to offer a viable project to its co-venturers for sanction and subsequent development. It then describes the construction work and successful delivery of the project and illustrates how the field has been produced since coming on stream in early 2000. It also discusses the reservoir modelling carried out since coming on stream to assist the decision whether to drill further wells for production or water injection purposes.
System-Modular Management of "Smart Assets" for Recovering the Remaining Potential
Authors: Appleford David E. , Lane Brian W. , Andrews Nicholas J. A. , Smith Ronald G. , Beer Brian W.
Published: December 2007

Abstract/Introduction

This paper on System-Modular Management presents an efficient, cost-effective method for the development, operation and control of "smart asset" hydrocarbon reservoirs. This method may be successfully utilised for new, mature, marginal or deepwater fields. The paper describes the method and identifies its operational and cost advantages over other development methods.
Fibre Optic Sensing - Case of "Solutions Looking for Problems"
Authors: Eriksson Klas
Published: December 2007

The unique physical attributes and performance characteristics of optical fibers has been well-known for many years, and indeed the transmission properties for data communications was well-known long before full commercialisation was possible for the telecommunication industry. In today’s perspective, it is difficult to believe that fiber optic data transmission systems were indeed "solutions looking for problems", from the early 1970’s. Today we think of high bandwidths, data communications on fibers as extremely routine for the telecom industry.

Similarly for oilfield sensing solutions in the subsea and downhole oil and gas industry, a large number of developers have been supplying potential solutions to sensing problems, but the problems of integrating these technologies with existing subsea and downhole facilities are not insignificant.

The paper will describe some potential solutions to the subject of integrating downhole and subsea fiber optic-based sensors with other subsea and downhole facilities, and identify the necessary interfaces, both physical, electrical and optical.

Some illustrative examples will be presented, and also an appreciation of the present state-of-the-art in fiber sensing for such applications.
WAG Pilot at VLE Field and IOR Opportunities for Mature Fields at Maracaibo Lake
Authors: Alvarez Carlos , Manrique Eduardo , Alvarado Vladimir , Samán Adnan , Surguchev Leonid , Eilertsen Terje
Published: December 2007

Light oil fields in Lake Maracaibo have been produced for several decades under depletion and waterflooding. Due to reservoir heterogeneity and complexity the traditional waterflooding oil recovery is not expected to exceed 30% of initial oil in place. Potential Improved Oil Recovery (IOR) methods capable to boost production from the mature fields are now under investigation and testing by the State Venezuelan Oil Company PDVSA. PDVSA's main IOR technology strategy is based on Integrated Field Laboratory (IFL) philosophy. IFL allows concentrating resources on modern technology evaluation, design IOR processes to solve regional problems, reduce the gap between laboratory screening and the field application phase for most promising recovery methods. The Water Alternating Gas (WAG) pilot at VLE-305 area of Lagocinco field is one of such IOR laboratory fields with the first immiscible gas injection pilot in Lake Maracaibo started in May 2000. The WAG pilot encompasses five production wells, one dual completion injection well and one observation well. The producing reservoir C-23 is a stratified sandstone with areal and lateral heterogeneities. Separator hydrocarbon gas is injected in the dual completion injection well in the WAG mode. Different sensitivity simulations were performed to design and optimize WAG injection strategy. The WAG pilot is now in its second stage of implementation and evaluation. Simulations are focused on tracer modeling and interpretation of production wells response.

Since available injection volumes of hydrocarbon gas for large scale WAG injection projects are not available in the area, other IOR alternatives are being considered. The VLE pilot is again used as a laboratory for screening other potential IOR technologies. Nitrogen injection in WAG and continuum mode, and cyclic water injection are strategies under consideration.

Nitrogen injection facilities will not be operational in the near future, therefore cyclic water injection is considered as an alternative for short-term production improvement under waterflooding. Cyclic injection can accelerate oil production and reduce water cut making production more economic and not requiring significant additional investments in the field. The preliminary evaluation of cyclic injection in the pilot area gives oil production improvement by 2-3%, and expansion of the process over a larger field area could give additional sweep improvement. WAG injection is estimated to improve oil recovery by 10-12% of STOOIP. WAG with nitrogen as injection gas may give 4-6% of STOOIP in increased oil recovery in comparison with waterflooding.
Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary
Authors: McGuire P. L. , Holt B. M.
Published: December 2007

This paper summarizes the conceptual development, reservoir simulation, and field testing of a new miscible EOR recovery technique at Prudhoe Bay. Two distinct variations of this technique have been evaluated.

The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers. It also creates a mobilized oil bank in the vicinity of the production well. The well can then be recompleted at the top of the reservoir and returned to production service, or used for some other purpose.

It is particularly advantageous to utilize this vertical drive process in conjunction with horizontal wellbores. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.

Simulation data indicate that the vertical MIST process could recover over 200 Mstb of incremental oil per well at initial rates of up to 1000 stb/D. Calculations for the lateral MIST process indicate potential recovery of more than a million barrels of incremental EOR per lateral.

Field results of the MIST process have been mixed, but overall are encouraging. Incremental EOR response from the first MIST lateral well is currently about 1400 Mstb, resulting in a technical and economic success. Response from three subsequent MIST lateral injectors varied widely. The first vertical well MIST showed little response, but it did provide valuable insight into the performance of the process at Prudhoe Bay. The subsequent vertical well MIST, which had a much larger volume of injected MI, was very successful and has currently recovered over 600 Mstb. Cumulative incremental EOR from the MIST wells through July, 2000, is over 5000 Mstb, with average incremental oil production rates over the past four years of about 4000 stb/D.
Experience of a Reservoir Waterflood Failure and Remediation Treatment in the Stag Reservoir, Australia
Authors: McDiarmid Allan , Ivor Alexander , Ion Andy , Thompson Jeffrey
Published: December 2007

The Stag field operated by Apache Energy Limited is located on the North-West Shelf Australia. Waterflooding is used to maximise production rates and reserves recovery. An unusual failure of the reservoir occurred in late October 2000, between a subsea horizontal injector and a platform based horizontal producer, 2130 ft apart. In effect, a reservoir short-circuit was created between the wells. This reservoir failure circumvented the waterflood and had the potential to isolate reserves between the two wells. Analysis of the failure data indicates the short-circuit was caused by high stresses in the weak reservoir formation. The failure appears to be a wormhole like failure.

A tracer study was implemented to provide information on the short circuit dimensions and to design a remedial treatment. The tracer took 2 hours 50 minutes to travel between wells indicating direct communication and a volume of the short circuit flow path in the order of 150-190 bbls.

Lack of isolation options through the uncemented pre-perforated liners would make any re-mediation difficult and expensive. This provided motivation to first attempt remediation by a comparatively inexpensive polymer treatment injected through the subsea injector and into the short-circuit. Following the polymer treatment, a cement squeeze through the producer was performed to block the short circuit.

This paper reviews the unusual reservoir failure, the tracer study, polymer treatment and subsequent cement shut-off. Included is detail on treatment designs, implementation utilising existing platform equipment and interpretations of the results.

This paper is a helpful case study to those designing and implementing water shut offs, identifying waterflood problems and testing low cost re-mediation alternatives. The paper raises an alternative failure mode that could be experienced in waterflood operations in weakly consolidated reservoir rock.
Horizontal Openhole Gravel Packs Boost Oil Production in Brunei
Authors: van Vliet J. P. M. , Lau H. C. , Skilbrei O. B. , Rahman Sakamrin H.A. , Bernardi L. A. , Shumilak E. E. , Halal A. S.
Published: December 2007

In the last three years, openhole horizontal gravel packs have been used extensively in Brunei Shell Petroleum as a sand control method in horizontal wells. Several reasons contributed to the wide application of this completion method. First, production data indicated that horizontal openhole reservoir sections completed with stand-alone screens showed productivity decline possibly caused by screen plugging. Second, gravel packing increases the inflow area and moves damage away from the screen, thus delaying or minimising screen plugging. Third, being an openhole completion a horizontal openhole gravel pack gives a lower skin than a cased-hole completion.

To date, Brunei Shell Petroleum has successfully installed twenty-one horizontal openhole gravel packs with lengths ranging from 100 m to over 1000 m. The unique challenges for horizontal gravel packing in Brunei reservoirs include shallow true vertical depth, long horizontal lengths up to over 1000 m, hole sizes ranging from 6" to 9-7/8", and well paths that crossed faults and long shale sections. Current production from the wells completed with openhole gravel packs accounts for some 18% of Brunei Shell's total oil production.
Assessment of Dulang Field Immiscible Water-Alternating-Gas (WAG) Injection Through Composite Core Displacement Studies
Authors: Nadeson Ganesan , Md. Zain Zahidah , Sayegh Selim G. , Girard Marcel
Published: December 2007

Composite core laboratory displacement studies were undertaken jointly with the Petroleum Recovery Institute, Alberta, Canada to obtain key laboratory data needed to evaluate the applicability of this WAG mode oil recovery scheme in Dulang field. Composite core technology was chosen over conventional single coreflood test as the former provides larger pore volume for fluid contact and movement, reduces saturation end effects and allows assembly of cores from different sands.

Waterflooding was very successful in recovering 56.8% of the original oil in place. Oil water relative permeabilities were derived from the waterflood data and showed the core to be water-wet. Two cycles of gas and water flooding were carried out in rapid succession. In total, about 6.2% of the original oil in place were recovered additionally as a result of these floods. There is also an indication that some more oil may have been recovered from the core by vaporization into the gas stream. The composite core showed evidence of permeability loss and the pressure traces during the floods were quite noisy. This is probably due to the movement of fines and blockage/clearing of pore throats. Geological examination of the core material supports this observation since they were found to contain kaolinite and illite. These possibilities of altering the reservoir rock's flow properties need to be taken into account when designing field applications.
Evaluations of Sub Horizontal Well Performance with Optical and Electrical Probes
Authors: Mas C. , Walterhouse B. , Van Vliet J. P. M. , Rahman S. H. A.
Published: December 2007

Innovative sensing technologies allow direct detection and quantification of oil and gas in multiphase flows. Similar to its sibling electrical probes, the new optical sensor has four probes. The probes are evenly spaced in the pipe cross section on the arms of a centralizer-like tool. The probes orientation in space is monitored through the use of an integrated relative bearing sensor. Image of the gas flow in the well bore is then generated from the measurements of the individual sensor.

Although electrical probes have been available in the industry for several years, its collocation with the full-bore spinner's cage is relatively new to the industry. In the threephase flow environment, the electrical probe gives water and hydrocarbon holdups.

The case examples presented in this paper illustrate the first application of tandem optical and electrical probes in Asia. Operational and interpretation aspects of the surveys in 2 subhorizontal oil wells are discussed in the paper.
Defining the Evolve Gas Rate and Composition from the Crude Oil During its Storage in Tanks
Authors: Braganza E. M. , González E. L. , Rost E. J. , Salleo A. M.
Published: December 2007

Upstream management and technological constant anxiety about production, transportation and storage or the crude oil includes gauging, running, and measuring processes variables (such temperature, API gravity, sediment and water, true boiling point, true vapor pressure) and consequently the evolves vapor rate in order not to removed it to the air as an atmospheric residual product but to be metered accurately to design properly the processes and operations to used it.

Using tools such HySim, crude oil destilation and crude oil viscosity curve, it can be performed a complete oil characterization, defining composition, properties and of course the rate of the evolves gas during its storage in tanks.
Artificial System - Plunger Lift - Time of Fall of The Plunger Under Operative Condition of Well of Petroleum
Authors: Braganza Eduardo , Rost Enrique , Gonzalez Esteban , Salleo Antonino
Published: December 2007

The study consists on analysing the times of fall of the plunger in Plunger Lift Artificial System, the speed to which the fall becomes weightless, the influence of the characteristics of the gas, of the production pipes, of the flows of gas remainders, the plunger weight.
Effect of Acidizing Additives on Formation Permeability During Matrix Treatments
Authors: Frenier Wayne W. , Hill Donald G.
Published: December 2007

Matrix acidizing treatments are performed to increase the permeability of oil and gas formations and to remove various types of damage. Mineral acids, organic acids and chelating agents are used to stimulate carbonate formations and to remove damage. Sandstone formations are usually treated with mineral acids (usually containing some HCl and HF) to remove damaging solids or liquids. Usually, stimulation in sandstone is not achieved. While a reactive fluid must be present to dissolve the damage or to remove part of the formation, numerous "additives" can be used to aid the penetration of the fluid or to perform other important tasks. To enable the reactive fluid to be pumped from the surface through the tubing and into the formation, corrosion inhibitors usually will be required to protect the metal from attack by the fluid itself. Surfactants, solvents, iron control agents, non-emulsifiers and several other types of agents also may be present.

There is increasing concern and some evidence (H. A. Nasr-El-Din, SPE 56712) that the additives adsorb onto the formation (or scale) and may actually be a cause of increased damage. Stimulation of carbonates frequently results in the formation of highly permeable wormholes, so adsorption of the additive may not be as important as damage caused in sandstone formation where damage removal is the primary goal. However, it is very possible that the additives may alter the surface kinetics during limestone acidizing, and thus change the degree of penetration or the efficiency of wormhole formation.

To understand some of the effects of additives on acidizing operations, we have studied some commercial corrosion inhibitors, surfactants and solvents during treatments of simulated sandstone and carbonate formations. The goal of the tests was to determine if the additives are damaging the formations due to adsorption or precipitation or altering the removal of damage or the dissolution mechanisms. Two major techniques were used: linear core flood tests and rotating disk tests. Using these methods, we have determined the effects of selected additives of the effectiveness and kinetics of reaction of HCl and chelating agents on limestone and Berea sandstone.

The effects of the additives depend on their individual chemical structure as well as the fluid and the formation being penetrated. In general, additives that are highly soluble in the fluid had less effect than agents that are insoluble or dispersible in the fluid. We have also shown that some additives can change the break-through volume during carbonate stimulation tests, thus altering the effectiveness of the treatment. In the paper, we will describe tests conducted at various temperatures, including tests run at 350 °F to evaluate hydroxy chelating agent formulations14,15 for use in matrix stimulation of carbonates.
Coreflood Evaluation of In-Situ Gelled Acids
Authors: Taylor K. C. , Nasr-El-Din H. A.
Published: December 2007

Three different commercial formulations (Company A, B and C) of in-situ gelled acids for matrix acid stimulation were compared in carbonate coreflood experiments at a temperature of 100 °F (38 °C) and at acid concentrations of 5 wt% HCl. The in-situ gelled acids contained a polymer, a cross-linker and a breaker in addition to corrosion inhibitors and surfactants. The coreflood experiments were done with small acid volumes (0.3 to 1.0 PV) so that permeability could be measured before acid breakthrough occurred. After acid injection, permeability was measured in both forward and reverse directions to assess the damage induced by the polymers used in these systems.

The concentration of cross-linker in the coreflood effluent samples was measured since precipitation of the cross-linker may lead to formation damage. It was found that in-situ gelled acids reduce permeability of low permeability carbonate reservoir rock. The polymer in these formulations is the primary source of the permeability reduction. Cross-linker was retained in the reservoir cores during injection of in-situ gelled acid.

Detailed viscosity measurements of each in-situ gelled acid were made as a function of equilibrium pH. Only Acid C showed significant in-situ gelation behavior in 5 wt% HCl.