bluuebunny/crossref_metadata_2025 huggingface dataset:
Deep Duals Simplified
Authors: Webster K.R. , O'Brien T.B.
Published: December 2007

This paper presents information on simplified down hole dual equipment using two packer-bore receptacles installed as an integral part of the production liner. One receptacle is on top of the 5-1/2 inch casing liner and the second is at the crossover between the 5 inch and 5-1/2 inch casing as shown in Figure 1. The seal assemblies that fit into the packer-bores are both run on the long tubing packer-bores are both run on the long tubing string. The short string has a stinger with seals that fit into the upper dualflow seal assembly.

There are several advantages to dual packer-bore receptacle completions. Both packer-bore receptacle completions. Both tubing strings and seal assemblies are recovered by straight pickup, leaving the inside diameter of the casing unrestricted for remedial work. Cost to drill permanent type packers and the formation damage that takes place while drilling is eliminated. There are no mechanical devices such as latches and holddowns to stick. The simplicity and minimum number of required operations reduces the chances of mechanical failure.

Stimulation of both zones takes place the same day with all the permanent equipment and the wellhead in place. Treatment of each zone consists of several stages using 15% HCl acid. The number, size, and placement of the deep penetrating burr-free perforations is designed to produce good diversion of the acid into all intervals of interest within a zone.

Four wells have been completed by HNG Oil Company using the dual packer-bore receptacle method. Potentials and deliverabilities have ranged from very high to small, depending on the formation development. The first well has been on production without failure for 2 years at production without failure for 2 years at 30 to 40 MMCF per day.

Introduction

Four wells have been dual completed by HNG Oil Company using the dual packer-bore receptacle method. The packer-bore receptacles were installed in a combination 5-1/2 inch by 5 inch production liner. One receptacle is on top of the 5-1/2 inch casing and the other is a part of the crossover between the 5 inch and the 5-1/2 inch casing as shown in Figure 1. Both of the seal assemblies that fit into the receptacles are run on the long tubing string. The short string has a stinger with seals that fit into the upper seal assembly.
No Fluid-Loss and No Damage Gravel-Packing
Authors: Franco Z.A.
Published: December 2007

A new method of gravel-packing a well is presented emphasizing the removal of installed damage, the prevention of new damage by avoiding formation fluid loss, and the use of an inexpensive and safe frac-pack tool.

Introduction

In unconsolidated formations, even for low overbalance, the rate of fluid loss is considerably high. The fluid loss generally causes damage which, in many cases, may require a workover job to be removed If the operator allows fluid loss to the formation, some problems such as water-in-oil emulsion, shale swelling, water block and salt precipitation may occur.

This work shows a new design in gravel-packing (GP) operation, which allows setting a sump packer, perforating, flowing the well for damage removal and gravel-packing in just one run, thus permitting to work in an underbalance way. The new design also presents a new fracpack tool which is simpler and less expensive than conventional tools.

The new design was conceived to solve critical problems in gravel packing in Dourado Field, in the northeastern Brazilian Continental Shelf. The use of the traditional methods resulted in very poor well performance. The lack of compatibility between rock and water base fluid was considered to be the main reason for the problem. The application of the new gravel-packing method turned-out to be the key for the successful development of the field.

Literature Survey

Recent papers concerning GP stress the need to avoid completion fluid interaction.

A high-density pre-pack followed by auto-injection of salt cushion to seal the perforations before GP and the utilization of a ceramic flapper-valve in the top-inside liner after GP are nowadays useful in solving this problem.

These methods do not avoid but just reduce fluid-rock contact. And they do not allow in many cases the use of a total rock-compatible fluid, as diesel oil, for instance, due to the high formation pressure gradient and the risk of overbalance trips.
Coring Samples and Obtaining Geomechanical Properties for Wellbore Stability Analysis in Deepwater Brazilian Horizontal Wells
Authors: de Sá Andréa Nicolino , Soares Antônio Cláudio
Published: December 2007

Deepwater exploitation is a risky and difficult task. This may be especially true when dealing with high deviated or horizontal wells producing from friable sandstone reservoirs such as those found in the giants fields Albacora and Marlim located in Campos Basin, offshore Brazil.

The determination of rock mechanics parameters in unconsolidated sandstones is an important step to better caracterize the rock, providing important inputs for better well planning, drilling, completion and production.

For poorly consolidated material, the task of keeping samples intact to be used in the Rock Mechanical Lab is very difficult. Thus a review of all the coring, core handling procedures and also the geomechanicals tests procedures to the direct measurement of rock strength and static mechanical properties is made.
Application of New Technologies to Horizontal Wells in Venezuela
Authors: Guimerans R. , Tovar J. , Pinto F. , Bolivar L. , Martinez A.
Published: December 2007

In Venezuela, at Maracaibo Lake (west) and Anzoategui-Monagas (east), there are reservoirs that have been under production for more than 30 years, which are presenting now low reservoir pressure. This situation has prompted the search for new technologies to maintain or increase the production in these zones. So far the technology that has been more successful is horizontal drilling, including the use of aerated drilling fluids and multilateral wells.

Up to date there are some 700 horizontal wells in Venezuela, with an average initial production of 800–1000 BPD per well. The majority of these wells are drilled setting a casing on top of the productive zone and changing the drilling fluid to one designed to properly seal and minimized formation damage. There are areas in Lake Maracaibo where the equivalent reservoir pressure is less than the density of water; the horizontal section is drilled with a mixture of air and water based fluid to achieve 3.5 – 6.5 ppg at bottom.

Multilateral horizontal technique has started with the design of wells with two arms, each in a different sand and opposite direction. Production can be commingled or set separately if needed.

This paper provides details of field applications of these technologies, production data and future projections.

Introduction

Horizontal drilling, as an emerging technology, had made possible an improvement in production from depleted reservoirs or from remnant narrow sands. In Venezuela, horizontal wells are drilled in two main areas: Maracaibo Lake in the west region and Anzoategui-Monagas in the east region, see Fig. 1.

Since the beginning of horizontal drilling in Venezuela, more than 600 wells had been drilled and over 1500 wells are expected for the year 2000 as Fig. 2 shows. These horizontal wells include mostly reentry wells to increase production of depleted reservoir from new exposed sands and new wells in narrow sands in order to incorporate remnant crude from them. From now on in this paper whenever horizontal wells are mentioned it should be taken as including both, new and reentry wells.

Due to the increase in horizontal drilling, technical aspects of the application of this technology in Venezuela are presented in this paper focused mainly in Maracaibo Lake. Improvement of application of horizontal drilling with other technologies, as aerated drilling, will be included.
The Influence of Heat Transfer on the Two-Phase Flow Behavior in a Wellbore During Transient Pressure Tests
Authors: Fairuzov Y.V. , Gonzalez J. , Lobato G. , Fuentes F. , Camacho R.
Published: December 2007

In this paper a numerical model was developed for the analysis of two-phase flow and heat transfer in a wellbore during a buildup test. The predictions of the model were tested with field data measured in a deep oil well. A detailed study of the influence of heat transfer between the wellbore and the surrounding earth on the bottomhole pressure response during well testing was carried out. The numerical results demonstrated that the variation of fluid temperature with time has a small effect on the bottomhole pressure buildup. The study revealed that an accurate prediction of temperature distributions in the wellbore and in the formation at the moment of shut-in is important for a correct description of the wellbore fluid flow behavior.

Introduction

Most of pressure buildup tests are performed by shutting in a well at the surface to reduce costs. In this case, at early times the bottomhole pressure response is a result of a dynamic 'interaction between the reservoir and the wellbore Therefore, understanding the physical phenomena occurring in a wellbore is important in the analysis of well tests. Several factors affect the pressure buildup during a well test, namely,

afterflow

phase redistribution,

fluid inertia and

heat transfer between the wellbore and the surrounding formation.

The first three above mentioned effects have been extensively studied in previous work. However, little information concerning the effect of heat transfer on the bottomhole pressure has been presented. Much of the past work on wellbore heat- transmission has concentrated on the development of methods for predicting the wellbore fluid temperature distribution in producing or injection wells. Most of the reported methods are based on steady-state models of wellbore fluid flow. To determine the formation temperature the transient heat conduction equation is solved analytically or numerically. However, during well testing the wellbore fluid flow is essentially unsteady. Under such circumstances, a steady-state wellbore flow model, which assumes equal flow rates at the inlet and outlet of the well, cannot be used to evaluate the effect of heat transfer on the bottomhole pressure response. The objective of this paper is to improve the understanding the processes occurring in the wellbore during a buildup test by taking into account the heat transfer between the fluid flow and the formation. For this purpose, a numerical model was developed to simulate the two-phase flow and the heat transfer in the wellbore Model validation was carried out through a comparison of computed results with field data. A detailed study was performed to investigate the effect of heat transfer on the bottomhole pressure buildup.
Effects Of Well Placement And Critical Operating Conditions On The Performance of Dual Well SAGD Well Pair In Heavy Oil Reservoir
Authors: Chan M.Y.S. , Fong J. , Leshchyshyn T.
Published: December 2007

The technical feasibility of applying the Steam Assisted Gravity Drainage (SAGD) process to a 10–20 m thick Saskatchewan type of heavy oil reservoir with an overlying gas cap and an underlying aquifer was examined via numerical modeling. The results suggest a potential reduction on SAGD oil recovery and process efficiency in the presence of a gas cap, an aquifer, or worse, by a combination of both. The oil recovery can be reduced by up to approximately 75% depending on the reservoir setting. Oil recovery can be increased by up to 25% by offsetting the injector from the producer from their conventional SAGD well configuration, or by adopting a staggered well pattern. There is diminishing benefit and deterioration in the SAGD process efficiency when the producer drawdown is set at more than 10–20% of the injector pressure and/or when the producer fluid withdrawal rate is higher than around 150% of the CWE steam injection rate. Some of the preliminary results suggest that the SAGD process for such heavy oil reservoirs can be enhanced through steam-gas co-injection, water-alternating-steam injection, or simultaneous steam-gas- bottom water injection.

Introduction

The continued success of the application of the SAGD process at the Athabasca oil sands Underground Test Facility (UTF) in Alberta has lead to a gradual diversification by the Canadian oil industry to application of the SAGD technology from the oil sands environment to heavy oil reservoirs such as those found in the Province of Alberta and Saskatchewan in Canada. Recent reported advancements in a few heavy oil thermal operations had further heightened interest in applying the SAGD technology to heavy oil reservoirs under a wide spectrum of reservoir conditions. This paper examines, via numerical modeling, the technical feasibility of applying the SAGD process to a 12 API heavy oil reservoir with 10–20 m of pay in the presence of an overlying gas cap and an underlying aquifer; the anticipated production characteristics; the issues on well configuration and well placement; key operating parameters; effects induced by the gas cap, aquifer and a combination of the two; and the potential for enhancing the SAGD process in this class of heavy oil reservoirs.
Design Considerations for a Heavy Oil Multi-lateral Well
Authors: Boardman D. W.
Published: December 2007

A generalised methodology is described for the complete modelling of multi-lateral well performance by using a network pressure solver in a numerical simulator to solve for the interaction between well branch inflows and completion pressure drops. The paper illustrates the importance of taking into account well trajectory, completion diameter and the positioning of the artificial lift, for heavy oil multi-laterals. The results of a design study for a multi-lateral well in an 11 API oil reservoir are outlined, and the necessity for economic ranking of results, in light of significant differences in well costs, highlighted.
Candidate Selection for Removal Treatment Based Upon improved Flowback Analysis: A Case Study
Authors: Carr Michelle A. , Yang B. Helena
Published: December 2007

Poor well performance due to permeability and conductivity damage can often be attributed to unbroken gel residue or inadequately reduced filtercake on formation faces. These forms of polymeric damage can negatively impact production rates by restricting the flow of oil or gas from the formation. Remedial treatments have been applied to wells exhibiting this type of damage using acids, oxidizers and enzymes. These removal treatments, when applied to accurately diagnosed polymer damaged wells and effective breaker systems are utilized, have shown to increase well production dramatically. However, polymer damage is only one of many factors that might be responsible for impeding optimum hydrocarbon flow. Therefore, the key to the success of a removal treatment is proper evaluation for polymeric damage when selecting a treatment candidate.

An improved flow back analysis has been recently introduced as a series of tests for polymer damage and for the evaluation of treatment load recovery. The testing procedures involved in that analysis can also be applied in candidate selection for remedial treatments and for monitoring the resulting clean up progress. Samples are analyzed before and after the treatment to determine total carbohydrate content, molecular weight distributions and the standard pH and viscosity measurements. The utilization of this improved analysis can assist in the selection of appropriate candidates and further direct treatment design. Several case histories on low performance wells are presented and include laboratory data to demonstrate candidate selection. Treatments with enzymes were used and detailed results are provided to evaluate the amount of polymer recovered. This paper also presents a guideline for use in the selection of candidates for remedial treatments.
Optimization of Bit Performance for Qatar's Offshore North Field
Authors: Martin Thomas B. , McKinnell Dave , Labrugere Philippe , Besson Alain
Published: December 2007

This paper describes the methodology and the results of a successful partnership between operator and service companies that improved the drilling performance and economics for the development of the North Field in Qatar. Fifteen high rate gas wells were delivered within designated directional targets, ahead of schedule and under budget.

The systematic use of a new methodology for bit selection, linked with an excellent level of communication and confidence between different parties involved in the drilling operations, was a major reason for the drilling success.

The different sections drilled were mainly made up of limestone, marl, and shale, but also anhydrite in the top portions of the well. In the lower sections, hard and soft limestone alternates withhighly compacted shales and dolomites. Penetration rates were greatly enhanced and bit performance improved by more than 100% in some instances.

The optimization of the performance took into consideration three aspects:A very tight schedule, where the optimization phase had to be performed within a limited time frame: Four wells were planned to be drilled back to back with two jack up rigs from two production platforms. After this short phase, batch drilling was expected to be performed for more than 20 deviated wells.The formations to be drilled presented a high complexity and heterogeneity where hard stringers alternate with a soft or a very compacted rock, and where in the lower section of the hole, a typical pseudo plastic behavior of the rock has to be anticipated.The well designs, casing depths, and bit types had to be in harmony with the drilling environment, the formation, and provide effective performance. New bit designs, more adapted to the technology available had to be developed or identified.

The use of roller cone bits and motors was planned and used in the top hole sections. The use of PDC bits associated with extended steerable motors and/or turbines was considered as potentially providing the best performance in the intermediate and bottom sections.

The early bit designs were modified based on wear patterns of dull bits. These enhancements and modifications were one of the major reasons in improved drilling performance and helped reduce the total drilling time from 75 days to 56 days per well. The challenges were met successfully, the most economical options selected and earned out ahead of time and under budget.
Environmental Regulations for Drilling Operations in Saudi Arabia
Authors: Abu Khamsin S. A.
Published: December 2007

There are several environmental regulations that any drilling and workover contractor must follow when working in Saudi Arabia onshore and offshore areas. These regulations are corporate, national, regional and global in nature. These environmental regulations are established to control drilling operations to minimize its impact on the environment.

The purpose of this paper is to summarize the requirements listed in the environmental regulations that pertain to drilling operations. AH these requirements must be followed and adhered to by operators when working for Saudi Aramco in its operating areas. Also discussed are the plans of implementation by operators to insure compliance of the regulations.

These regulations pertain to (1) discharge to marine environment from drilling operation, (2) waste water treatment re-use and disposal, (3) protection of marine life, (4) pollution control and environment protection, (5) waste management for mud, cuttings and rubbish.
Drilling Optimisations in Yibal Field, Oman
Authors: Koole Koos , Verwey Piet
Published: December 2007

In Yibal, a mature oil field in Oman, a number of optimisations have been implemented as a result of constantly challenging historically accepted procedures and by aligning the objectives of PDO, the Drilling Contractor and Service Contractors through the use of incentives. Although these may not include any step changes in technology, in combination they have realised a 25% reduction in drilling costs over a 2 year period (see fig. 1).

Introduction

The Yibal field, situated in the desert of North Oman, was discovered in 1962. The main oil reservoir is located within the Upper Shuaiba formation at 1370m TVD. The oil column attains a maximum thickness of 100 m with no primary gascap present and hydrostatic pressures. The STOIIP is estimated at 550 million m3 with an expected ultimate recovery factor of 55 %.

Since coming on production in the early 1970's the field has produced approximately half of its ultimate recoverable reserves but it is still responsible for almost one third of the current production target of 135,000 m3/day.

Since the middle of 1994 additional horizontal drainage points in the field have been provided by drilling side-tracks instead of new wells (see figure 1), and with 438 wells present in Yibal and the rapid production rate decline there are many side-track candidates available. Any new Yibal well requires 5 or 6 casing strings (due to the presence of shallow gas, artesian flow, requirement for sweet aquifer isolation, and isolation of a gas reservoir) and costs in the order of US$ 1.6 million with an average duration of 30 days. In comparison, a side-track takes on average 18 days and costs just under US$ 1.0 million. In the first half of 1996, 15 horizontal sidetracks were drilled, each producing initially 500-1000 m3/day.

Although the wells are shallow their complexity is increased by the horizontal design and the frequent presence of total losses and unstable shales. In this environment of repetitive but complex and very intensive work, it is a continuous challenge to obtain increased optimisation of the drilling operation. However this challenge must be undertaken in order to reduce or even maintain the UTC per barrel of oil for PDO.
Deep Water Riser System Design and Management
Authors: Thorogood J.L. , Train A.S. , Adams A.J.
Published: December 2007

The risk of a fatigue failure of a critical weld in a marine riser employed in deep water, harsh environment operations is judged to be high. This paper describes how the dynamic excitation caused by vortex shedding can be quantified and used to predict fatigue accumulation while drilling. Estimation of the initial riser fatigue state is of considerable importance, for this good record keeping by the rig owner is required.

The paper concludes that wells can be drilled in harsh environments without the use of vortex suppression devices so long as fatigue accumulation is monitored. Drilling contractors play a key role in maintaining accurate records of riser fatigue history and managing an appropriate inspection programme. The fatigue accumulation predictions are only as good as the models used in the analysis, which at this stage must be treated with some care.

P. 25
Innovative Rotary Closed Loop System - Engineering Concept Proven by Extensive Field Application in the Adriatic Sea
Authors: Donati Franco , Oppelt Joachim , Trampini Alessandro , Ragnitz Detlef
Published: December 2007

The Rotary Closed Loop Drilling System (RCLS) was developed as a joint venture project between a major oil company and a leading service company. A long term research and development program within the service company was supported by the Italian oil company over the past five years. The resulting drilling system is capable of steering a wellpath while the drill string continues to rotate, so penetration rates are not sacrificed while slide drilling, as is necessary when using conventional steerable technology. Furthermore, this unique system has several integral downhole sensors, enabling two-way communication between the downhole system and surface, while also providing FEMWD data. In addition, several automated drilling functions enable the system to steer independently. During this operation, surface personnel are able to intervene at any time through direct control using a downlink signal. This paper will provide a detailed insight into the project's engineering strategy during the development. The paper also presents a review of the first year of field application, mainly in the Adriatic Sea offshore Italy, which concluded the prototype period. The philosophy of the pilot field application program is briefly described and an overview is given of the ongoing engineering efforts, as well as the considerable future development potential.

P. 305
Using Suction Technology for Deep Installation of Structural Pipe in Deepwater
Authors: Faul G.L. , Audibert J.M.E. , Hamilton T.K.
Published: December 2007

Suction technology has the potential to enhance structural well casings, foundation piles, and caissons in deepwater. The enhancements should provide increased integrity as well as cost savings for future deepwater projects. Suction technology provides an attractive alternative to the current methods of jetting, driving, or drilling and Cementing. The application of suction to install large diameter, shallow set anchors and foundation caissons has already proven to be valuable. Extending this technology to relatively small outside diameter, deep set tubes can provide significant cost savings for deepwater well and foundation construction.

P. 417
Innovative Way To Cement a Liner Utilizing a New Inner String Liner Cementing Process
Authors: Fuller M.S. , Littler M. , Pollock I.
Published: December 2007

It has long been recognized that the conventional process of running an inner string when cementing liners provides for protection of the liner inner diameter from cement during the installation of a well bore liner. Over the years, this process has created concern about being able to verify the location of the cement, accidentally cementing the inner string in place inside the liner, leaving the inner string full of cement upon pulling, or not being able to circulate the liner clean after cementing.

A new inner string liner cementing process has been developed that addresses these concerns and offers solutions to the potential problems. The new process incorporates ways to prevent these problems from occurring. Since the inner string volume will be more consistent than the total liner volume, the volume of cement can be accurately calculated to insure that the shoe track is not over displaced. This is very important since the standard shoe track length can be greatly reduced. In addition, this new system allows you to clean the liner I.D. and displace the well prior to tripping out of the hole with your hanger setting assembly. A cost savings is realized due to the elimination of a separate trip in the hole to clean and circulate the well.

This paper will describe the conventional liner cementing process along with the improvements that have been incorporated into the new system.

P. 501
Outsourcing Can Be Used Successfully Within an Existing Well Construction Organization
Authors: Harder C. , Drennon P.
Published: December 2007

Since the first drilling department was formed many years ago, sizing drilling organizations has been a constant challenge. Fluctuations in drilling activity create a moving target for optimizing drilling personnel requirements. Recent changes in industry patterns have altered both organizational structures and job descriptions. When properly implemented, total outsourcing of well construction, whether on a project or geographic basis can effectively maximize the flexibility of an organization.

Four years ago a well construction organization was formed combining company personnel and a fully integrated, outsourcing engineering firm in-house. The outsourcing arrangement was made to address varying activity levels. To date a total of 144 projects and 57 million dollars of expenditures have been outsourced. The work was performed on a project management basis which required very little supervision by the operator.

The expected benefit of buffering manpower requirements during cyclical activity was not the only advantage experienced with outsourcing. As drilling activity increased, well construction projects were prioritized so that complex projects were handled by company personnel while the engineering firm worked on lower risk projects. In addition, since the outsourcing firm had other clients this opertator continuously benefited from the firm's external experience and perspective, and allowed a continuous competitor analysis approach to evolve throughout the entire organization.
Variations in Multilateral Well Design and Execution in the Prudhoe Bay Unit
Authors: Aubert Winton G.
Published: December 2007

Declining volumetric rates characterize hydrocarbon production from the Prudhoe Bay Unit (PBU) of Alaska's North Slope. Economics of declining production forces Prudhoe Bay operators to seek ever-decreasing well bore construction costs. Multilaterals are designed to reduce well costs on a "per barrel" basis, as multiple producing branches access greater reservoir volume or more than one reservoir.

This paper describes various multilateral well configurations currently in use in the PBU. Descriptions are substantiated by multiple multilateral well case histories. Included are geologic and targeting considerations, operational details, and details of specialized hardware used in drilling new and sidetrack multilateral wells at PBU. Oil production data are also presented.

Open junction multilateral technology is shown to be viable and applicable at PBU. Multilaterals have been executed successfully, and well production performance has been excellent. PBU asset business interests are shown to be well served by application of multilateral technology.

P. 807
Data Integration and Automated Stress-Profile Zonation Enhance 3D Hydraulic Fracture Design
Authors: Boonen P. , Frisch G. , Storozhenko K.
Published: December 2007

A new method is presented to compile all the available data from wireline logging or logging-while-drilling in a format suitable for direct input in 3-D hydraulic fracture models. Because of the differences in format and data density, log data are not always used optimally in 3-D hydraulic fracture modeling. They do provide however the most comprehensive and continuous parameters for borehole stress profile, permeability index, elastic moduli, lithology, porosity and fluid saturations. An automatic zoning technique divides the data into consistent intervals based on stress contrast. The representative design parameters are then computed for each zone. The outputs are a blocked stress profile and zoned fracture design parameters.

The availability of a stress profile based on rock mechanical analysis from wireline logs, microfrac tests and core data specifically designed for use in 3D hydraulic fracture simulators has stimulated the use of these data in the selection of candidates for stimulation treatment. Post-frac radioactive tracer logging has shown that the automatic zone selection identifies natural barriers to hydraulic fracture extension. This new product provides a synergistic approach to hydraulic fracturing in which wireline logs and rock mechanical analysis are fully utilized together with microfrac tests, core data and production history to optimize the execution and economics of the field development process.

Improved candidate selection (wells and reservoirs) for stimulation treatment in a South Texas gas field increases production while reducing the number of fracture treatments and total stimulation cost. Pre- and post fracturing logs are compared to show adequate stress profile compilation.

P. 327
Mapping Hydraulic Fracture Growth and Geometry Using Microseismic Events Detected by a Wireline Retrievable Accelerometer Array
Authors: Warpinski N.R. , Branagan P.T. , Peterson R.E. , Wolhart S.L. , Uhl J.E.
Published: December 2007

Technology has advanced to the point where microseismic monitoring of hydraulic fractures can provide critical information for fracture optimization. Important elements of a monitoring system include the receivers, the telemetry system, and automatic processing of the vast amounts of - data. Procedures and additional data requirements are discussed and examples of the important results which can be obtained are illustrated.

P. 335
Waterflooding Heterogeneous Reservoirs: An Overview of Industry Experiences and Practices
Authors: Gulick Karl E. , McCain William D.
Published: December 2007

This paper reviews waterflood management practices, highlighting key industry papers. It is intended to move readers up the "learning curve" and provide a road map for implementing and operating a successful waterflood project. It will assist reservoir engineers, production-operations engineers, and development geologists who are involved in or are contemplating waterflood operations.

The paper addresses operating philosophy, well spacing (density), pattern development (selection), completions, injection water, and surveillance. Although these factors are presented from a west Texas perspective, they are applicable to reservoirs having a high degree of vertical and areal heterogeneity.

In addition to a brief history of waterflooding, the paper reflects "lessons learned" through years of experience in waterflooding and CO2 flooding carbonate reservoirs, principally in west Texas. This experience has been gained through work in both a major and a large independent oil company, through interfacing with outside operators of all sizes, and through consulting for small, independent oil companies.
New Composite Fracturing Plug Improves Efficiency in Coalbed Methane Completions
Authors: Guoynes J.C. , Toothman R.L. , Berscheidt K. , Malimasura P.R.
Published: December 2007

Success in coalbed methane (CBM) development projects can be attributed to efficient hydraulic fracturing of multiple coal seams and quick online gas production. Because the coal can be naturally fractured, friable, and somewhat plastic in nature, successful stimulation can be challenging.1 Typical cased or openhole completion methods involve hydraulic fracturing of the coal seams. The seams may either be commingled and fractured together or isolated to perform staged fracturing treatments. Zonal isolation historically has been achieved when operators set inflatable plugs in the openhole or cast iron plugs in casing between stimulation intervals. Many operators use foamed fracturing fluids to enhance flowback and fracture closure after the initial treatment.

Inflatable packers have not been reliable in openhole completions, and this technology is developing at a slow pace in the industry. Difficulties also occur in either drilling or retrieving cast iron plugs used to isolate stimulation intervals in cased hole CBM completions. When multiple cast iron plugs are used in a single well, the difficulty in drilling out these plugs increases with the number of plugs. The increased difficulty is caused when the steel slips are drilled through and the remaining portion of the plugs drop on top of the undrilled plug or plugs left below. This remaining portion of the upper plug rotates freely on the fracturing sand and lower plug, increasing the drillout time on successive plugs. Retrievable plugs are difficult to remove because the fracturing sand left in the wellbore frequently enters the retrievable plug, creating releasing problems. Removal of cast iron plugs has taken as long as 8 days in some CBM completions.

A new composite epoxy-glass fracture plug was designed for use as an aid in the completion of multiple coal seams, allowing staged zonal treatment with flowback capabilities after treatment. The fracturing plug is made of an easily drillable, lightweight, composite material with no metal. The composite plug greatly reduces drilling time and drilling difficulties.

Case histories of more than 100 CBM wells that were completed with composite fracturing plugs are summarized in this paper. The new plug, combined with nitrogen-foam stimulation, improves completion efficiency and greatly reduces associated rig time in CBM operations. In addition, the new plug design greatly reduces the potential for downhole tool problems, including wellbore debris. Use of the new plug allows the operator to achieve wellstream production 30 days sooner than with previous plugs, allowing more rapid degasification of the coal.

P. 603
The Dual Laterolog-Rxo Tool
Authors: Suau J. , Grimaldi P. , Poupon A. , Souhaite P.
Published: December 2007

Introduction

The Laterolog*, developed by H.G. Doll, has answered the need for a tool capable of producing useful resistivity measurements even when R /R is very high, as in the case of carbonates and evaporites drilled with salty mud. In invaded formations where R is greater than R it is better adapted for R determination than the induction log. The laterolog has also provided improved thin-bed resolution. Field laterologs have taken two different forms: Laterolog 7 using seven small electrodes, and Laterolog 3 with a central electrode and two long guard electrodes. As shown in Figs. 1a and 1b, in each tool a measure current i, from the central electrode is focused into the formations by bucking currents, i, of the same polarity. These are fed from symmetrical, short-circuited electrodes above and below the central electrode. The intensity of this focusing current (i a) is automatically and continuously adjusted so that under most conditions the measure current (i) flows outward from the sonde into a horizontal slice of formation of approximately constant thickness.
An Approach to Analyzing Multiple Causes Of Subsidence
Authors: Green Joseph P.
Published: December 2007

Negative changes in surface elevation (subsidence) have been recorded in many parts of the world and generally attributed to any one of several possible causes. Down-hole monitoring equipment is effectively being employed in some fields to relate subsurface compaction to surface subsidence, while in many other areas the necessary background history for such monitoring is not available.

This paper is a modified case history, wherein the relative amounts of three independent, simultaneously acting causes of subsidence were determined without the benefit of subsurface compaction surveys.

Through this analysis, subsidence control measures can be effectively implemented without the risk of over-reacting to one cause while possibly neglecting another.

Introduction

Previous attempts to adequately explain Previous attempts to adequately explain subsidence in a certain Southern California oil field (anonymity is required, as some of the basic data are restricted) were unsuccessful because single-cause theories had been employed.

This paper relates the effect of each of three independent causes of subsidence, acting simultaneously in the field. From this analysis, a workable method was developed for predicting either the rate of future predicting either the rate of future subsidence, or the means and location for providing corrective measures.

Causes

Subsidence throughout the world has been well documented, particularly where it is associated with fluid extraction. Shallow, freshwater production was responsible for some 25 feet of subsidence at Mexico City, and some areas in the San Joaquin and Santa Clara Valleys of California have decreased 28 and 13 feet, respectively. In Tokyo, Japan, some two million people now live below mean high tide (13). The list of areas where subsidence, associated with fresh-water withdrawal, has been less dramatic is nearly endless.

Oil-field operation associated with subsidence was documented nearly 60 years ago in the Goose Creek field, Texas.
Differences in Behavior of Fresh and Aged East Texas Woodbine Cores
Authors: Richardson J.G. , Perkins F.M. , Osoba J.S.
Published: December 2007

Laboratory experiments have shown profound differences in the behavior of so-called "fresh cores" from the East Texas field and of the same cores after extraction with organic solvents. The residual oil saturation remaining after water flooding "fresh cores" was appreciably lower than the corresponding saturations after flooding extracted cores. This behavior was also reflected in the water-oil relative permeability-saturation relations, which were more favorable for high oil recovery from the fresh cores.

These differences were evident not only in the amount of residual oil left after water flooding, but also in the saturation water remaining in the core after displacement by oil. Residual water saturation after displacement of water by oil was higher in the fresh cores than in the extracted cores. Capillary pressure-saturation relations were also different for the fresh and extracted cores.

Imbibition experiments indicated that both fresh and extracted East Texas cores are preferentially water wet, but the rate of imbibition of water was higher for samples after extraction than it was for fresh core material.

Introduction

Several years ago a series of water flooding tests was made in the laboratory on a number of Woodbine core samples from the East Texas field. These samples had been stored in containers open to the air and were extracted with organic solvents before they were subjected to the laboratory tests. After water flooding, the residual saturation of kerosene, which was the oil used in the tests, was found to average about 30 per cent.
Seismic Environment of the Southern California Coastline 1: Palos Verdes to Dana Point
Authors: Ploessel Michael R.
Published: December 2007

The southern California coastline lies within one of the more active seismic regions of the world. The Newport-Inglewood Fault System is within 12+ miles of the coastline, crosses the shoreline near Newport Beach, and from seal Beach to Dana Point is within 2+ miles of the shore. Point is within 2+ miles of the shore. In addition, the San Andreas, San Jacinto, San Gabriel, Sierra Madre, Whittier, Norwalk, Elsinore, and other active or potentially active fault zones are within 60+ miles of this coastal area.

Two major earthquakes have been recorded as heavily damaging the area. On December 8, 1812, a major earthquake wrecked the Mission San Juan Capistrano, (maximum Modified Mercalli Intensity IX) and on March 10, 1933, the Long Beach Earthquake, (Magnitude 6.3, Maximum Modified Mercalli Intensity IX) with an epicenter off Huntington Beach did considerable damage to Long Beach and Los Angeles.

The record of past seismic activity indicates that this area, which is daily becoming more densely populated and developed, will experience an earthquake of magnitude 6 or greater within the next 50 to 100 years. Such an earthquake may produce intense shaking lasting 30 to 60 seconds or longer with peak ground accelerations of 30 to 50 per cent gravity (Maximum Modified Mercalli Intensity VIII to IX). Such shaking could seriously damage many of the structures within the area, trigger new landslides, and reacivate existing landslides. The low lying alluvial area from San Pedro to Newport Beach will experience more intense shaking and damage than the cliffed bedrock areas of Palos Verdes, Corona del Mar, Laguna Beach, and Dana Point. The alluvial area, with the Point. The alluvial area, with the water table within a few feet of the surface will possibly experience liquefaction and ground lurching. All future construction within this area should be designed and built with due consideration of the areas seismic environment.
A Visual Study of Waterflooding a Microlayered Sandstone
Authors: Gring Larry M. , Caudle Ben H.
Published: December 2007

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Introduction

One task that the production engineer faces when evaluating the potential success of a waterflooding project is the forecasting of recovery at water breakthrough. The heterogeneous nature of sandstones makes this extremely difficult. However, experimental laboratory and field work have presented the engineer with some insight presented the engineer with some insight into how to approach the problem. To contribute to this insight, the author has investigated waterflooding a micro-layered sandstone.

It has been deter-mined that microlayers exist in man sandstones that appear to be homogeneous. Figure 1 is a photographic enlargement of typical photographic enlargement of typical microstrata investigated. To better understand the function of the microlayers in the waterflooding process, small linear laboratory flow cells have been constructed and subjected to the waterflooding process. The author sought to determine whether consideration of each stratum individually with to respect to its porosity and permeability was necessary, or whether permeability was necessary, or whether an average permeability and an average porosity would be acceptable. porosity would be acceptable.

GEOLOGY OF THE SANDSTONE

The sandstone used as the porous media in the flow cells was collected from an outcrop in southern Oklahoma near Calvin. The Calvin formation is a medium to silty grained, grey and brown, massive and thin bedded sandstone. The lower unit of the formation has tongues of sandstone and siltstone which break off of the bottom of this unit and intertongue with the shale of the underlying Senora formation. It is from this lower unit that the samples for this investigation were collected. Figure 2 is an example of the sandstone.

CONSTRUCTION OF THE FLOW CELL

The original sandstone samples taken from the Calvin site were in layers ranging from four to ten inches thick. The shale had weathered sufficiently to permit removal of large blocks of the sandstone. These large blocks were sliced into slabs approximately 5/8 inch thick. The slices were made perpendicularly to the bedding planes so that as many layers as possible were exposed. The dimensions of the cell were sketched on these slabs, with the longer dimension being parallel to the layering. A diamond cutting saw was used to cut the pattern from the slab of sandstone. The pattern from the slab of sandstone. The rectangularly shaped stone was then placed on a surfacing machine to cut away sufficient sand to make the top and bottom surfaces of the stone parallel to one another. The surfacing was required so that when the stone was machined to the desired thickness, it would be uniformly thick.
Natural Gas From Abroad
Authors: Hunsaker Barry
Published: December 2007

To keep pace with our burgeoning natural gas requirements, most experts agree that even under the most favorable circumstances, this country is going to have to manufacture high Btu pipeline gas from coal and oil products, and import huge quantities of natural gas from abroad in the form of LNG (Liquefied Natural Gas). How much LNG? In the range of 1 to 2 trillion cubic feet per year by 1980 and in the range of 1.5 to 4.0 trillion cubic feet per year by 1985. Where will this LNG come from? The most likely of the present known sources are Algeria, Trinidad, Venezuela, Nigeria, Russia and Libya. Of these, Algeria contains very large reserves of natural gas, conservatively estimated at 100 to 150 trillion cubic feet. One field alone—the Hassi R'Mel Field—contains over 60 trillion cubic feet of recoverable reserves, making it one of the two largest gas fields ever discovered in the entire world. And the first project for the import of huge quantities of LNG for base load purposes project for the import of huge quantities of LNG for base load purposes will be the El Paso-Sonatrach project which I am going to describe. Sonatrach is the Algerian state-owned company charged with the responsibility of finding, developing and commercializing Algerian hydrocarbons. It is a large company staffed with relatively young, but technically competent, men who have assumed tremendous responsibilities and who are working about as hard as any group I know.

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