bluuebunny/crossref_metadata_2025 huggingface dataset:
Developing the Micro-Flux Control Method—Part 1: System Development, Field Test Preparation, and Results
Authors: Santos H. , Reid P. , Jones J. , McCaskill J.
Published: December 2007

The paper presents the first part of the development of a closed loop drilling system for the management of downhole pressures. It is based on the Micro-Flux Control (MFC) method and uses real time simulation techniques connected to a process control loop that facilitates full back-pressure control over the well. The method has been described previously and is only briefly summarized here.

This paper reviews the challenges and development hurdles that were overcome to commence field testing of the MFC method. The paper also describes how the first version was defined, based on feed-back received from operators, service companies and equipment suppliers.

A combination of established field-proven UBD technology and existing conventional drilling techniques are used, integrating with a software-based well control system. This allows the operator to maintain an effective, safe, on-line watch on the well control process at all times and in real-time.

The paper describes the results of the first series of tests conducted at a test well facility, where influxes were detected and automatically controlled with less than 1 bbl of pit gain. These outstanding results confirmed the ones previously obtained using a full size drilling simulator in the first part of the development; these results are also presented in the paper.

The paper finally describes the next steps to be taken for the system to become fully available for application in a wide range of wells.
Life-Cycle Profile Control in Subhydrostatic Wells of South Oman
Authors: Ojukwu K. I. , Mueller K. , Murshidi A. , Masroori M. , Edwards J. , Tramaille D.
Published: December 2007

Profile modification of injection and production wells is of major importance in South Oman heavy oil reservoirs. This is because injected and produced water must be controlled to optimize reservoir sweep and oil production.

Profile control in artificial lift wells is also a common dilemma because the intervention involves re-completing wells to achieve logging-while-pumping necessary for detecting unwanted intervals.

In 2004, two completion philosophies were adopted to allow hoist-free re-entry as well as provide a cost effective life-cycle solution. One is the replacement of smart wells with segmented horizontal wells. This completion allows for effective diagnosis and isolation of watered-out sections. The other is replacing the upper completion of producers in sub-hydrostatic reservoirs with dual Christmas Trees. That makes it possible to measure the inflow profile while pumping through the second tubing.

A proactive measure was taken by field-testing a new technology capable of satisfying all basic requirements. The technology is a wireline deployed rubber and carbon fiber sleeve expanded by hydraulic pressure to set flush against the casing. Heat is applied to polymerize the resin before deflating and retracting the running tool. The patch thickness can withstand both burst and collapse pressures, leaving sufficient internal-diameter in 7-in and 4 ½-in casing for subsequent deeper intervention.

Phase-1 trial was successfully completed in 3 water injectors late in 2004. Phase-2 trial which was planned for 2 oil producers are still being mobilized and will be executed in third quarter of 2005, late for publication in this paper.

Some unique characteristics of this technology made it attractive; namely (1) ability to deploy via smaller size tubing to expand & set in larger perforated liners, thus eliminating rig/hoist requirement, (2) high depth precision using CCL correlation, (3) possibility of bypassing existing patch to isolate downstream toe area, (4) possibility to by-pass isolated areas to re-perforate lower zones and safely retrieve the bloated gun barrels, (5) applying gentle and even hydraulic force contour-to-contour to set against un-reinforced liners, (6) cost effective solution of higher success rate compared to chemical treatments. The trials proved to be the first campaign of its kind to be successfully completed with 100% success rate, while meeting all expectations.
Aluminum Alloy Tubulars for Oil And Gas Industry
Authors: Gelfgat M. Y. , Basovich V. S. , Adelman A.
Published: December 2007

Oil and Gas industry requires a significant amount of tubular goods to meet their operational objectives. Drill pipe, casing, tubing and risers must be designed and manufactured to accommodate present and future tendencies of drilling deeper, longer, faster and more efficiently while maximizing production for every well drilled. The most important feature of aluminum alloys used as materials for tubular manufacturing is that they provide exceptional strength-to-weight ratio. This simply means that the length of aluminum alloy pipe string suspended under its own weight would be about two times longer than steel. This feature allowed development of aluminum drill pipe which has an excellent potential in extended reach drilling of wells of 15 km long. The last five years of field applications in West Siberia have proven that ADP has high reliability and life expectancy. Equally superior performance is projected for aluminum casing, tubing, and line pipe. Use of aluminum drilling riser strings in deep waters of offshore Brazil and GOM helped to establish that aluminum alloy is very reliable construction material for some of the most difficult applications in the petroleum industry. This experience provides us with confidence in continuing to develop new products for the industry, such as completion and production risers.
Young Resources in the E&P Industry: Key Issues to a Successful Start
Authors: Bruni T. , Tealdi L.
Published: December 2007

It is in the very early time of one's employment that many decisions, both from the company side and the employee's side, are taken that will significantly impact the individual's career and professional development. This first phase of any anyone's career is hardly ever one during which major/actual work is carried out by the new hire. For non-experienced employees, in most large/major E&P companies, this induction period is mainly focused on training which is widely recognized as carrying vital importance, as it guarantees the safeguarding and perpetuation of the company most precious asset: that of a competent and skilled workforce. In the oil business, many "intangibles" like the employee potentials and competence are a critical factor for success and an important source of competitive advantage for the companies. With the exception of very few employers, the induction period is often organized in a "static" manner, without much opportunity to for tailoring the program based on the employee's feedback. This poses potentially dangerous consequences that might finally result in a missed chance of realizing the full potential of the young resource and, in some cases, in the loss of talents that represent an important strategic asset for the companies.

The paper presents a new approach to the development of young resources, and it encompasses several themes revolving around training, potential and how to realize all of the value residing in the human resources.
Development and Application of New Downhole Technology To Detect Water Encroachment Toward Intelligent Wells
Authors: Jackson M. D. , Saunders J. H. , Addiego-Guevara E. A.
Published: December 2007

Electrokinetic potentials are generated when fluids flow through rock. We have investigated whether changes measured in electrokinetic potential using permanently installed downhole electrodes could be used to detect water encroachment towards intelligent oil wells. Downhole electrodes in cemented arrays have been successfully utilized in resistivity measurements, but have not previously been used to measure electrokinetic potential. One reason is that it has not been possible to relate changes in potential with changes in saturation. We have reviewed the existing literature and conducted laboratory experiments to determine how the electrokinetic potential varies with water saturation, brine salinity and other key reservoir parameters.

We have used the results to simulate numerically the electrokinetic potential response measured at a well during oil production. Preliminary results suggest that encroaching water causes changes in the measured electrokinetic potential which could be resolved above background electrical noise; indeed, water could be detected several 10's to 100's of meters from the well. We have also investigated the optimum response of an intelligent well equipped with downhole inflow control valves. In a simple, conceptual reservoir model, production is significantly enhanced if encroaching water is detected before it arrives and flow into the wellbore is properly controlled.

Our findings raise the novel prospect of an oil field in which the wells can detect the approach of water and respond appropriately. Such wells offer enormous potential economic and environmental benefits, particularly in fields which are difficult to access or dangerous to operate.
Modeling Permeability in Coal Using Sorption-Induced Strain Data
Authors: Robertson E. P. , Christiansen R. L.
Published: December 2007

Sorption-induced strain and permeability were measured as a function of pore pressure using subbituminous coal from the Powder River basin of Wyoming, U.S.A. and high-volatile bituminous coal from the Uinta-Piceance basin of Utah, U.S.A. We found that for these coal samples, cleat compressibility was not constant, but variable. Calculated variable cleat-compressibility constants were found to correlate well with previously published data for other coals. Sorption-induced matrix strain (shrinkage/swelling) was measured on unconstrained samples for different gases: carbon dioxide, methane, and nitrogen. During permeability tests, sorption-induced matrix shrinkage was clearly demonstrated by higher permeability values at lower pore pressures while holding overburden pressure constant; this effect was more pronounced when gases with higher adsorption isotherms such as carbon dioxide were used. Measured permeability data were modeled using three different permeability models that take into account sorption-induced matrix strain. We found that when the measured strain data were applied, all three models poorly matched the measured permeability results. However, by applying an experimentally derived expression to the strain data that accounts for the constraining stress of overburden pressure, pore pressure, coal type, and gas type; two of the models were greatly improved.
Identifying the Timing and Sources of Damage in Gas Storage Wells Using Smart Storage Technology
Authors: Spivey J. P. , Brown K. G. , Sawyer W. K. , Gilmore R. G.
Published: December 2007

Most underground gas storage (UGS) wells suffer loss of deliverability over time, often due to unknown causes. Consequently, deliverability maintenance is one of the primary concerns of UGs operators. The authors believe that a significant aid to identifying the potential causes of damage in UGs wells would be an increased knowledge of when the damage develops. specifically, does the damage develop during injection operations, during withdrawal operations, when a change in flow direction occurs, or continuously? Unfortunately, identifying trends in damage versus time using conventional buildup and falloff tests would be operationally challenging and prohibitively expensive.

An increasing number of UGS operators are using electronic flow measurement (EFM) systems capable of collecting high-frequency (10 to 15 second intervals) pressure and flow rate data at the wellhead. Over the course of normal storage operations, wells will often be shut in for short periods of time. Wellhead EFM data collected during these shut-in periods can be analyzed as buildup or falloff tests. Consequently, UGs operators having wellhead EFM systems often have sufficient buildup and falloff test data to identify trends in damage over time.

Tools have been developed to automatically 1) filter high-frequency EFM data from gas storage wells to identify shut-in periods that can be analyzed as buildup or falloff tests, 2) perform the appropriate pressure transient analysis of the test data so collected, 3) generate semilog and log-log analysis plots, and 4) generate composite graphs of apparent skin s' vs. flow rate and s' vs. date. These tools also allow the user to review and fine-tune the test analyses, and exclude results from any questionable test periods.

The system has been used to analyze data from 20 wells in a major gas storage field for the period December 2003 through May 2005. since wellhead pressure and flowrate data are recorded for each well at 15-second intervals, the system had to be able to process large amounts of data. A total of 357 shut-in periods were identified, 207 of which were analyzable. Three wells had no interpretable tests, while eleven of the wells had 8 or more analyzable tests.
Commingled Production Experiences of Multilayered Gas-Carbonate Reservoir in Saudi Arabia
Authors: Al-Shehri D. A. , Rabaa A. S. , Duenas J. J. , Ramanathan V.
Published: December 2007

Saudi Aramco employed extensive matrix and acid fracturing treatments in the development of Saudi Arabian nonassociated gas carbonate reservoirs. The target reservoir is the Permian Khuff Formation which is the major non-associated gas reservoir in the prominent Ghawar Field, eastern Saudi Arabia. The Khuff reservoir is stratigraphically divided into four correlative zones, namely Khuff-A, B, C, and D in downward sequence. Khuff-B and C are the two major reservoirs with distinctive hydraulic characteristics. Khuff-A and D zones mostly are either discontinuous or have poor to non reservoir quality.

Saudi Aramco is pursuing commingled production selectively as a part of the gas development plan to extend the well's economic life and to meet its growing domestic gas needs.

Since the Khuff-C has better reservoir quality with larger gas reserves, it was completed by itself during the initial period of the field development. Later, the commingled production by adding the Khuff-A and B has become part of the overall strategy to offset the natural decline from Khuff-C and maximize gas production and extend the wells' life.

This paper will review the acid fracturing and stimulation practices employed by Saudi Aramco in the Khuff-Carbonates. The criteria used to select suitable candidates for the commingled production and techniques employed to quantify flow contributions from each individual zone after commingling the production will be reviewed. The production performance, lessons learned, business impact and the way forward will be discussed.
Torque and Drag Modeling for Horizontal Openhole Completions
Authors: Rezvani R. , Techentien B.
Published: December 2007

Proposal

Since horizontal openhole sections are now being drilled to lengths that exceed 20,000 ft, placement of the completion string (CS) to planned total depth (TD) may not be possible under a proposed drilling plan. During the early years of horizontal-well construction, the hanging weight of the completion string was usually adequate to push it to TD. With the extreme lengths being attempted today, it is important to model the well before attempts are made to run the planned completion to determine 1) whether the strength of the CS can stand the strains (tension, compression, and torque) of installation, and 2) whether there is enough weight in the upper CS to push the lower CS to TD. A software model that uses a wide range of well parameters to enable the operator to predict possible tension loading, compression loading, and torque limits on the CS during installation has long been available. This paper discusses the software and how it can be used in modeling well completion systems.

To calculate the applied forces on the completion string requires the use of a wide range of well parameters and a specialized software program that will allow the prediction of loads and stresses that can be safely applied on the CS during installation. If the modeling process indicates that the CS will not stand the stresses of installation without (1) failing from tensile loading, (2) buckling from the compression load, or (3) failing from rotational torque, a different well plan can be devised or other remedies employed. Charts developed from actual case histories illustrate how the use of torque and drag modeling can be advantageous in all phases of well completion.
Software, Fluids, and Downhole Tools for Successful Sand Cleanouts in Any Wellbore Geometry Using Small Coiled Tubing
Authors: Gilmore T. , Leonard R. , Steinback S.
Published: December 2007

The use of coiled tubing to clean sand from well bores remains one of the industries major areas of activity in well intervention. Recent research work programs have focused on sand transport and cuttings bed modeling with both Newtonian and power law fluids. In large diameter holes, annular velocity is very low, regardless of the coiled tubing's size. Performing well clean outs in these very difficult conditions without the use of expensive or logistically challenging solutions is often impossible. Even with large diameter coiled tubing or concentric tubing strings, the problem of successfully cleaning wells of sand can persist.

This paper will describe a method of cleaning sand from a well, regardless of its geometry or hole size, in a low-pressure environment with small coiled tubing. A description of the philosophy used to clean these wells; the computer modeling utilized; as well as the unique rheological properties of the fluid used; during the clean outs will be made. In addition to fluids and software modeling, a description of the unique jetting tool employed will be made. Case histories will be provided demonstrating sand clean outs performed exactly as predicted by the software modeling in an unprecedented time by utilizing all of these "tool box" items.

The potential to clean any well in one single optimized run in to and out of the well is significant because, as fields mature, more challenging clean outs will continue to be presented. Additionally, clean out economics and the risk of failure will become increasingly important since mature wells and fields are by their very nature unable to bare excessive intervention costs. The importance of using software, down hole tools and fluids for cleaning sand from these wells will be demonstrated. The application of all of these techniques simultaneously offers the opportunity to clean all wells economically with existing standard coiled tubing units.
Medusa Project: Integrated Planning for Successful Deepwater Gulf of Mexico Completions
Authors: Soter K. , Malbrough J. , Mayfield D. , Holland J.
Published: December 2007

The following will outline the Medusa Field development and completion design process highlighting an integrated approach between engineering disciplines and service providers to exploit the enormous amount of exploratory well data. The Medusa development, located in Mississippi Canyon blocks 538 and 582 offshore Louisiana, is a truss SPAR allowing for both dry tree production and multiple subsea tiebacks. A field overview from a geological and reservoir perspective, along with the drilling and field development considerations, will be summarized.

The initial phase of the Medusa truss SPAR development includes ten compaction-tolerant FracPac completions in six dry-tree wellbores. Phase II wells included the drilling of two subsea tiebacks. One was drilled and deemed uneconomic while the second, Medusa North, was completed and tied back in early 2005.

The paper will show how the information gathered during the drilling phase was applied to the completion design to ensure long-lasting, reliable and profitable wells.
The Viability of Single-Trip Sand-Control Completions in Deep Water—A Case History
Authors: Cole B. , Franklin B. M. , Cody R. , Littleton R.
Published: December 2007

Escalating development costs and increasing deepwater activity emphasize the need for reducing well completion costs dramatically. The evolution of single trip systems in the Gulf of Mexico Shelf provides proven technology to complete marginal properties in deepwater.

Workstring trips on deepwater completions are the single most expensive operation; therefore minimizing trips can significantly reduce operational costs. Today, wells are being drilled deeper and therefore the impact of reducing the number of trips is significant. Single trip systems executed successfully in today's deeper environments can offer considerable savings. Realized project savings depends on the type infrastructure in place, i.e. Semi-Submersible, Drillship, Spar, TLP. Single Trip systems offer a viable option to reduce costs, however candidate selection and additional engineering considerations are associated with these systems.

The progression of single trip systems to multi zone completions systems is examined along with the inherent advantages they present. Based on the completion architecture and rig infrastructure in place tangible savings in excess of half a million dollars can be realized. Installation of single trip systems, a deepwater completion performed from a drill ship, and the cost analysis for the feasibility of this application is presented.
External Casing Perforating Provides Optimal Treatment Coverage in Horizontal Pay
Authors: Rodgerson J. L. , Ruegamer M. L. , Snider P. M.
Published: December 2007

Multi-stage treatments in horizontal wells have become the "Holy Grail" of the service industry. Combining horizontal drilling technology and multiple stimulation stages along the length of the borehole has allowed operators to develop many new reservoirs around the world. The Barnett Shale formation in Texas has received the most recent notoriety. Many techniques have been offered to optimize treatment coverage throughout horizontal intervals including limited entry, sliding sleeve; barefoot open-hole and coiled tubing (CT) completions. These techniques can be very efficient and provide good coverage in lateral completions, but time and again this is accomplished with a sacrifice of net pay. Some of these techniques can be somewhat time-consuming and expose the operator to undesirable risk.

A relatively new multi-stage treatment process optimizes perforation and treatment designs in either vertical or horizontal completions. The technique, known as "external casing perforating," allows the operator to perforate and isolate individual zones with as little as 15 minutes between treatment stages. As many as 17 discrete intervals have been treated within a 24-hour period in a vertical completion. In most cases elapsed time to first sales has been dramatically reduced.1 Production from these wells has been brought online quickly in a single rig-less operation without damaging and time-consuming shut-ins.

The paper will explain the external casing perforation technique in horizontal applications and compare it to other methods available in the industry. A major portion of the paper will focus on the field installations to-date and the operational methodologies employed to ensure success. Additionally this paper will describe benefits such as zonal isolation and ease-of-use and provide comparative success metrics for both conventional and horizontal applications.
Atlantis Batch Setting: Operational Performance Close to Perfection
Authors: Valdez H. , Fleece T.
Published: December 2007

Near perfect operational performance may sound a bit presumptuous, but when we look at the statistics around the Atlantis batch setting job performed by BP and the Transocean semisubmersible rig Deepwater Horizon, there is no doubt about the outstanding level of operational excellence reached by the people involved in the project and the reliability of the equipment utilized.

Planning and execution personnel strove to maximize utilization of rig multi-activity capabilities. The application of lessons learned from one location to another in order to improve the efficiency of subsequent operations was a major focus during execution.

As a result, the Atlantis batch set installed 60,239 ft of pipe in 24 subsea locations in an area of 2.4 acres in 91 days with no LTI's, no recordables, no incidents and an overall operational efficiency above 98%. See figure A1 for basic well schematic. Average installation time of the 36 in. x 26 in. x 20 in. casing strings in 6820 ft of water was 5.2 days per well.
Depressurization-Induced Gas Production From Class-1 Hydrate Deposits
Authors: Moridis G. J. , Kowalsky M. B. , Pruess K.
Published: December 2007

Class 1 hydrate deposits are characterized by a hydrate-bearing layer underlain by a two-phase zone involving mobile gas. Two kinds of deposits are investigated. The first involves water and hydrate in the hydrate zone (Class 1W), while the second involves gas and hydrate (Class 1G). We introduce new models to describe the effect of the presence of hydrates on the wettability properties of porous media. We determine that large volumes of gas can be readily produced at high rates for long times from Class 1 gas hydrate accumulations by means of depressurization-induced dissociation using conventional technology. Dissociation in Class 1W deposits proceeds in distinct stages, while it is continuous in Class 1G deposits. To avoid blockage caused by hydrate formation in the vicinity of the well, wellbore heating is a necessity in production from Class 1 hydrates. Class 1W hydrates are shown to contribute up to 65% of the production rate and up to 45% of the cumulative volume of produced gas; the corresponding number for Class 1G hydrates is 75% and 54%. Production from both Class 1W and Class 1G deposits leads to the emergence of a second dissociation front (in addition to the original ascending hydrate interface) that forms at the top of the hydrate interval and advances downward. In both kinds of deposits, capillary pressure effects lead to hydrate lensing, i.e., the emergence of distinct banded structures of alternating high-low hydrate saturation, which form channels and shells and have a significant effect on production.
Optimizing Maintenance and Inspection for New Offshore Installations
Authors: Brandt H.
Published: December 2007

Proposal

In recent years risk based approaches for planning and developing asset management strategies have emerged as effective means to prioritize spending on maintenance and inspection activities, whilst controlling the costs. Based on extensive experience from Risk Based Inspection (RBI) and Reliability Centered Maintenance (RCM) methodologies, a new integrated Risk Based Asset Management (RBAM) process has been developed in close cooperation with the industry. This integrated process is focused on effective prioritizing, screening and successfully implementing a maintenance and inspection program in order to effectively optimizing business performance.

Asset Operations is a complex process in which reliability, maintenance, safety and environmental issues all need to be addressed and related to business objectives and regulatory compliance requirements. The RBAM process acknowledges the fact that to improve overall profitability; maintenance, inspection and reliability must play a key role together with operations to assure understanding of the factors that affect asset (equipment) performance and availability. This allows development of a business driven asset management strategy that reflects not only the life cycle of the equipment, but also the specific financial targets of the operator.

This paper describes the framework of the Risk Based Asset Management (RBAM) process, and focuses on the methodology developed specifically for implementing a successful maintenance and inspection plan for new offshore installations and developments. The methodology will be illustrated by recent projects and lessons learned from real study cases, with focus on the importance of a successful implementation and the development of a continuous improvement process.
A Fully Adaptive Streamline Framework for the Challenging Simulation of Gas-Injection Processes
Authors: Gerritsen M. G. , Jessen K. , Mallison B. T. , Lambers J.
Published: December 2007

We propose a novel fully adaptive computational framework for the efficient simulation of gas injection processes. For flow, we employ a Cartesian Cell-based Anisotropically Refined (CCAR) grid method together with single-phase Multi-Level Local-Global (MLLG) upscaling. The combination of adaptivity and MLLG reduces process-dependency because it ensures that high permeability paths are well resolved. For transport, we use the Compositional Streamline Simulator (CSLS) that was designed for compositional processes. CSLS incorporates mesh adaptivity along streamlines. It adapts the streamline coverage to concentrate streamlines where needed to resolve transport, e.g. near solution fronts, and to reduce errors introduced by the mappings between the pressure grid and the streamlines.

These mappings are the primary sources of error if streamlines are updated sufficiently frequently and appropriate higher-order schemes are used for propagation of components along streamlines. We reduce the smoothing errors introduced by the mappings by a higher order mapping from pressure grid to streamlines. We use a Kriging algorithm to map from the streamlines to the background grid. Mass balance errors resulting from the mappings are effectively controlled by increasing the streamline density based on a local error indicator. The flexibility of Kriging allows us to include partially traced streamlines that are not required to begin and end at wells. This is not possible with the commonly used mappings that are based on flux weighting.

To reduce errors associated with fixing the pressure field between pressure updates, we developed a higher order global time-stepping method.

We demonstrate the potential of the framework with several calculation examples including 2D continuous CO2 injection, water alternating gas (WAG) displacements, and 3D field scale CO2 injection into a saline aquifer.
Context-Adaptive Project Management: A Scoring Model for Assessing Project Complexity and Uncertainty
Authors: Rahi A.
Published: December 2007

Oil & Gas service companies have used project management techniques to ensure that they can effectively deliver increased value to their customers. The success with these techniques can lead to a philosophy that if a few project management processes are good, then more must be better; or that what worked on one project should work on another. This can lead to frustration and inefficiencies where overly bureaucratic processes are dictated, or result in chaos when the processes applied are insufficient for the job at hand.

This paper analyzes key characteristics of several types of service company projects (integrated field rehabilitation, production, drilling, etc.) and commercial models (turnkey/lumpsum, joint ventures, performance, reimbursable (price book), etc.) to develop a scoring model that classifies projects by Uncertainty and Complexity. The model plots projects in this two-dimensional space and it is shown that projects within a quadrant benefit from similar project management approaches. This provides an adaptive and consistent means by which to calibrate the type and level of project management required to the context of the project. The model also highlights uncertainty and complexity "spikes" in a project's profile that can be addressed proactively in the proposal development and project planning stages. This approach was previously applied successfully in the software development arena1 and has been adapted and extended for the oil & gas industry.

Early applications of this approach have been promising in two case studies that we present. The first is a 2.5–year 350-well turnkey drilling project in the Burgos Basin of Mexico. The second case study is a 10-year integrated field rehabilitation (brownfield) project in the Casabe Field, located in the central part of the Middle Magdalena Valley basin, Colombia. The paper concludes with a discussion of this context-adaptive approach as a key input to overall project portfolio management.
Expandable Sand Screens Selection, Performance, and Reliability: A Review of the First 340 Installations
Authors: Jones C. , Tollefsen M. , Metcalfe P. , Cameron J. , Hillis D. , Morgan Q.
Published: December 2007

Expandable sand screens (ESS®) are a relatively new sand control system, which combines many of the properties of gravel packs with the ease of installation of a stand-alone screen. Although they have been used in a wide variety of applications, they are not considered a panacea and have an operational envelope, which is becoming clearer with time.

Weatherford's ESS system currently (June 2005) has 340 installations and over 700 years of combined production. A recent survey of the installations was analyzed in terms of performance and reliability.

The productivity performance of the ESS has been shown to be very good, with an average skin of 0.3 being achieved in recent openhole applications. ESS completions generally perform better than the baseline models. Where field comparisons were possible, they also performed better than alternative sand control completions.

Over the 340 ESS wells, ESS has a reliability comparable with other sand control systems, with initial failures less than 5% and a production failure rate of 0.021 failures/well.year. This gives a projected survival rate at 20 years of greater than 90%. This rate is expected to get better with improving operations, designs, systems and application selection.
Dealing With H2S in Heavy-Oil Thermal Projects
Authors: Monnery W.
Published: December 2007

There is an abundance of natural gas being discovered and produced that is slightly sour. According to a US Department of the Environment (DOE) survey that includes Canada, about 80% of current and new gas has a hydrogen sulphide (H2S) concentration of 1% or less. Of course, this must be treated to remove the H2S to meet sales gas specifications. For small scale (less than 50 – 100 kg) and large scale (greater than 20 tonne/d) of equivalent sulphur, current technologies appear reasonable. Conversely, for intermediate range (0.1 – 20 tonne/d) equivalent sulphur, current technology has proven to have high capital and/or operating costs and some processes are difficult to operate. Therefore, there is a need for an intermediate scale (0.1 to 20 tonne/d) process with lower capital and operating cost than those currently available. The applications of such a process range from the removal of H2S from acid gas at low pressure produced from the amine process to high pressure raw sour gas. There are additional challenges from sour gas associated with heavy oil thermal projects in that it is at low pressure and contains substantial C7+. The elemental sulphur produced should be of sales grade quality such that the handling of the product can fit into the existing sulphur infrastructure and sold into existing markets. Otherwise, disposal of the product becomes costly and in some cases becomes another environmental problem.

In answer to this need, Xergy Processing Inc. has developed a gas phase direct oxidation process for the above applications as well as treating heavy oil off-gas, fuel gas, power generation gas. The process has relatively low capital and operating costs and is easy to operate, with no equipment that is unfamiliar to the petroleum industry. Conversion to sulphur depends on the process configuration and pressure but ranges from 80% to 99.9+% based on lab and field data.
Run-and-Forget Completions for Optimal Inflow in Heavy Oil
Authors: Freyer R.
Published: December 2007

Heavy oil reservoirs generally suffer from low recovery factors and high operating cost. To optimize recovery and minimize operating cost, experience and insights should be collected to enable shift changes in development costs. Different options for enabling these developments are proven or suggested in this paper. Horizontal or deviated wells are considered the base case.

Heavy oil reservoirs often suffer from: Unconsolidation and sand production due to immature rockemulsions and annular solids transport causing plugging of screens and sand control failuresserious water or steam breakthrough due to mobility ratios preferentially producing unintended fluidsmarginal production rates due to high viscosity and low reservoir pressure.

In addition, steam floods are challenged by high completion costs due to extreme temperatures encountered, and high energy consumption due to production of high temperature fluids.

All of these factors contribute to reduced ultimate recovery and well life.

The paper describes case studies and concepts for the optimization of such heavy oil production systems, including uncemented completions which are very often beneficial to minimize well cost, minimize sand control challenges and maximize recovery.
Laboratory and Field Validation of a Sealant System for Critical Plug and Abandon Situations
Authors: Nagelhout A. C. G. , Bosma M. G. R. , Mul P. J. , Krol G. G. , van Velzen J. F. G. , Joldersma J. S. , James S. G. , Dargaud B. , Schreuder G. J. R. , Théry F.
Published: December 2007

This paper presents case histories and discusses the laboratory validation of a sealant system for plug-and-abandon (P&A) operations in critical gas wells close to habitations. To ensure long-term isolation both inside and outside the original casing, the plan was to mill out the casing and cement and to place the plug from rock-face to rock-face. The milled-out section was planned so that in the worst-case scenario the differential gas pressure would have to be supported by 25 m of cement plug, even though a greater height of cement would be placed inside the original casing above the milled-out section.

Two cement systems were designated as candidates for the plugging operation with slurry properties suitable for the application. The gas-sealing ability of the selected systems was validated with both small-scale and large-scale tests. One system, exhibiting both high flexibility and expansion, met the stringent specifications and did not leak until a differential pressure of more than four times the specification was applied. The paper will discuss the parameters of the selected system, thus providing guidelines for system selection for critical plugging operations. A detailed case history of one well (two plugs) is given along with the results from four other wells.
First Medium Radius Horizontal Well in Marrat Formation in Kuwait: Case History of Umm Gudair 56
Authors: Al-Saeedi M. , Al-Mutairi B. , Al-Enezi D. , Mahesh V. S.
Published: December 2007

Kuwait has been drilling and producing from the deep, sour Jurassic reservoirs during the past 20 years. These vertical wells penetrate heavily fractured, highly pressured reservoirs and produce high quality light oil. There are an increasing number of wells in which depletion, low reservoir pressures and poor reservoir rock quality have meant that they can no longer flow at commercial rates. Horizontal well technology can provide a means to increase reservoir section length and intersect possible oil bearing fractures, thereby enhancing well productivity.

This paper will discuss the challenges of designing and drilling the first deep, medium radius, high pressure well bore sidetrack, from an existing production well, into the Jurassic HPHT reservoirs.

These challenges include the necessity to mill up the existing liner hanger and 80 ft. of casing to allow for any future re-completion, the restricted drill string size of 3 ½″ due to the well being completed with 7 5/8″ casing to surface, the directional target constraints, the hole cleaning difficulties due to the restricted pump rates, hard formations with low drilling rates, drill pipe buckling, the ability to slide in the lateral, and to drill the well without gains, losses or differential sticking.

All these difficulties were tackled using optimized drill string designs, advanced milling and directional technologies including; medium radius build profile, lateral drilling with PDC/insert bits on motors equipped with ABI (at bit inclination) for enhanced steering capabilities and LWD tools. Using these technologies plus recommended practices developed by the operator and service companies enabled the establishment of record performances in Kuwait for this type of well.

The results of the drilling will be presented along with conclusions drawn on the overall operation which will then provide the basis for future optimization in the design and drilling of these types of wells.
Expandable Tubular Successfully Scab Off Severe Casing Leaks
Authors: Bargawi R. A. , Zhou S. , Al-Umran M. I. , Aghnim W.
Published: December 2007

The number of old wells completed with uphole packers showed a dramatic increase in casing leaks. The leaks were dumping aquifer fluid directly to the reservoir and vice versa. Many wells experienced this kind of problem.

The conventional practice to isolate these kinds of leaks was to run and cement a scab off liner. This resulted in running smaller production strings and consequently resulted in a dramatically reduction in the production rate and choking wells with high pressure it also limits future remedial workovers of developed future leaks.

Saudi Aramco launched a campaign to recover and salvage wells that had been affected by severe casing leaks and hot spot corroded sections. The solid expandable liner was introduced in two sizes of casing. Introduction and usage of this new technical application will have a maximum ID after setting the solid expandable to run the maximum tubing size, to achieve the highest production rate.

This paper will describe the successful application of this technology and its comparative advantages, including reduced cost and salvaging wells without the need to sidetrack as had been done before. The paper also includes some review of recently applied casing repair results in several wells.
Evaluation of Drillstring and Casing Instrumentation Needed for Reservoir Characterization During Drilling Operations
Authors: Nygaard G. , Fjelde K. -K. , Nævdal G. , Lorentzen R. J. , Vefring E. H.
Published: December 2007

New technology for transferring downhole data to the surface during drilling operations gives new possibilities for identifying reservoir parameters. More accurate data and higher data transfer rates from the drill bit will be available. In addition, new sensors might be introduced between the drill bit and the surface. Data from these sensors can be transmitted on-line to the surface.

When using a detailed dynamic model of the well and reservoir, the model can be calibrated using available real-time measurements. Improving the data transfer methodology provides measurements with higher accuracy. There are also possibilities of placing sensors along the drill string and incorporate these measurements into the model.

This paper evaluates methods for performing on-line reservoir characterization using available instrumentation. In addition, new sensor positions along the drillstring and along the casing are introduced and evaluated with respect to improvement of reservoir characterization.
A Unique Experience of Using Hydraulic Workover Unit (HWU) for Re-Entry and Drilling Operation Onshore Gabon
Authors: Yunus F. , Dufour J. , Ripayre A. , Mercier M. , Suro C. , Sredensek E.
Published: December 2007

Enhancing oil recovery in onshore mature fields is one of the important aspects of Total Gabon's activity. This involves workover or horizontal sidetracks on existing wells located on Total's various fields within Gabon.

For these operations, Total Gabon faces several challenges. Economical: these operations usually target relatively small oil reserves, therefore the drilling unit choice is a key factor in the operational economics.

Technical: variety of the well candidates is considerable with reservoir TVD ranging between 800 to 2500 meters.

Rig availability: over the past few years, increasingly fewer onshore drilling units were available in Gabon and none of them could fulfill both the economical and technical criteria.

The use of Hydraulic Workover Unit (HWU) was considered as a possible alternative. Fewer and lighter loads would have to be moved between locations. These units have a smaller foot print requiring less civil works and have almost similar capabilities as a light drilling unit.

A feasibility study was carried out and preliminary technical discussions were held with various contractors. It was concluded that this approach was indeed feasible, provided that some modifications were done to existing units: installation of an adequate mud system, improvement on existing rotary heads, reinforcement of the hydraulic power supply to allow 24 hours operations instead of the usual 12 hours.

The HWU campaign started in February 2004 and included three workovers plus four re-entries (horizontal sidetrack after milling casing).

Beside the increase in oil production potential of about 14000 bbls/day, the potential cost saving is about 3.5 Million US$ for the entire campaign compared to a conventional rig operation.

The project provided a valuable learning experience. The use of HWU for re-entry operations is now regarded as a proven technique
Slotted Completion for Sand Management: A Novel Screenless Completion Technique
Authors: Addis M. A. , Khodaverdian M. , Lee C. , Fehler D.
Published: December 2007

Three novel concepts have been identified which realise the benefits of screenless completions. The most developed of the techniques, the slotted completion for sand management, is described along with the underlying mechanism by which it is able to defer or avoid sand production.

The investigation of this novel completion is based on a laboratory testing programme centred around polyaxial cubical samples of Castlegate sandstone, subjected to a 3-d stress regime. The design of these block tests was based, in part, on numerical analyses, using in-house modelling capabilities for simulating Castlegate sandstone. The analysis assisted in defining the borehole and slot dimensions. The pretesting numerical analyses are presented, along with the laboratory block test results. Both the analysis and test results provide ‘proof of concept’ for the mechanisms underlying this novel completion technique.