bluuebunny/crossref_metadata_2025 huggingface dataset:
Critical Evaluation of the Ensemble Kalman Filter for Reservoir Parameter Estimation under Incorrect and Uncertain Prior Models
Authors: Jafarpour B. , Tarrahi M.
Published: September 2011

The Ensemble Kalman filter (EnKF) has recently been proposed for history matching reservoir models. The performance of EnKF depends on the representativeness of the initial ensemble of reservoir properties. The initial ensemble is commonly constructed by assuming a known geological continuity model such as a variogram. However, since geologic continuity models are derived from incomplete data and imperfect modeling assumptions they are subject to uncertainty. Neglecting this important source of uncertainty can lead to systematic errors and questionable estimation results. In this paper, we evaluate the performance of the EnKF under varying levels of uncertainty in the variogram model parameters. We first attempt to directly estimate variogram parameters from flow data and show that the complex and non-unique relation they have with the flow data provides little sensitivity for an effective inversion with the EnKF. We then assess the performance of the EnKF for estimation of gridblock permeability values under uncertain and incorrect initial variogram parameters and show that any bias in specifying variogram parameters tends to persist throughout the EnKF analysis although locally reasonable permeability updates may be obtained near observation points. We consider the uncertainty in the variogram model parameters and account for the full range of structural variability in the initial permeability ensemble. We show that under this assumption the EnKF update results are quite promising. We conclude that, in applying EnKF to realistic problems where the level of prior uncertainty may not be known, it is preferable to overestimate the uncertainty in geologic continuity and initialize the EnKF with a wide range of variability in property description than to overlook the variogram uncertainty at the risk of introducing systematic bias that cannot be corrected by the EnKF updates.
Optimization of Completions in Unconventional Reservoirs for Ultimate Recovery – Case Studies
Authors: Snyder Daniel J. , Seale Rocky
Published: September 2011

Over the last decade, an industry wide shift to unconventional plays has occurred due to advances in technology allowing for the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multi-stage fracturing are two technologies which have accomplished this. The two main methods of horizontal, multi-stage completions currently used in unconventional reservoirs are: cemented liner "plug and perf" and open hole, multi-stage fracturing systems.

This paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal, multistage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Case study examples are presented from a variety of unconventional reservoirs included including shale, tight sandstone and carbonate formations.

Operators working in a number of unconventional reservoirs, such as shales and other tight rock formations are experiencing faster than expected production decline rates, resulting in reduced long-term, ultimate recovery. This may be in part due to the abandonment of good fracturing practices, developed over the past 50 years, with the advent of horizontal, multi-stage fracturing. Issues such as near wellbore conductivity, flowback, and fracture tortuosity that can have a significant effect on the long-term production of wells need to be considered when choosing a completion method, particularly for unconventional reservoirs.

Unconventional plays are becoming a significant part of the oil industry today and will become a bigger part in the future. It is important that the reservoirs are completed optimally to make them as productive as they can be. The information provided in this paper is applicable to unconventional resource plays worldwide.
Use of High-Strength Coiled Tubing in High-Pressure/High-Temperature Perforating Operations
Authors: Makris K. , Barclay D. A. , VanArnam W. D.
Published: September 2011

A major operating company (operator) demonstrated interest in the development of high-strength (>125 ksi yield) coiled tubing (HST-CT) for use in high-pressure/high-temperature (HP/HT) fields in the central North Sea. The operator's objective was to perforate underbalanced (in base oil) with coiled tubing (CT) using up to 1,700 ft of guns in one run. The combination of the low hydrostatic pressure of the perforation fluid and high bottomhole-pressure results in high wellhead pressures. Therefore, the CT had to be strong enough to avoid collapsing while pulling the weight of the bottomhole assembly (BHA) and the string inhole from the working depth of a live well. Because of this, the CT needed to be carefully designed to minimize its weight without compromising its strength. Computer simulations were run for string designs made from the currently available materials but none were found suitable for the operator's objective, so the operator pursued the development of HST-CT.

A major CT manufacturer working in conjunction with a material supplier developed the product and, allied with a service company, proved the product suited the needs defined by the operator.

It was decided to run the HST-CT in a newly drilled well in the same area but in a shallower reservoir with sub HP/HT conditions as a test bed to determine any potential issues with the use of HST-CT in reverse-deployment perforating operations. This job was performed with a shorter BHA and a lower wellhead pressure than true HP/HT conditions. Some of the operational testing normally conducted in Houston, Texas was performed in Aberdeen, Scotland because of job-time restrictions.

The test results, operational details of the CT job, and observations and conclusions derived from the use of the HST-CT developed are discussed in this paper.

This project involved the first offshore application and the first commercial application of HST-CT worldwide. The importance of this project is highlighted by the increased number of unconventional reservoirs being perforated, thus increasing the need and demand for stronger CT.
Two-Stage Cementation of A Multilateral Junction, After Floating In The Casing
Authors: Brooks Robert
Published: September 2011

This paper presents a practical solution for successfully floating in the casing and performing second stage cementing of a multilateral junction. The drilling and completion objectives required a successful cement job on the 9–5/8 in (244 mm) × 10–3/4 in (273 mm) casing that would: Isolate the reservoir at the 9–5/8 in (244 mm) shoe.Isolate the multilateral junction and prevent hydrocarbons from entering the upper annulus during production.Provide support for the 9–5/8 in (244 mm) casing during exit window milling operations.

Due to the distance between the 9–5/8 in (244 mm) shoe and the multilateral junction point it was identified early in the planning stages that the chances of success for a single stage cement job completing these objectives was minimal.

With this in mind it was decided to perform the 9–5/8 in (244 mm) cementing in 2 stages. A multilateral well with a TAML Level 4 junction requires a cement sheath that provides 360 degrees of annular isolation. Full cement coverage also contributes to constructing a high-strength TAML Level 4 junction. Most junctions are placed at a depth which is considerably shallower than the motherbore casing shoe depth. Achieving full cement coverage at the junction depth may not be possible over long intervals. This scenario may require a secondary cement program. This is to ensure competent cement around the multilateral junction for support during the milling phase and isolation from the annulus in the event that a 360° phased perforation had to be performed on the whipstock.

Due to the trajectory of the wellbore it was necessary to float the casing in-hole using a "casing flotation technique." Air was trapped inside the casing and the first stage cement job was performed as normal using a 2-plug operation. The second stage cement job was subsequently carried out through a locking Port Collar with Metal-to-Metal (MTM) seals.

This completion method was utilized in an Upper Captain Sand dual-lateral infill well in the North Sea. After the casing had been successfully run to depth and the first stage cement job completed, a Port Collar operating tool was deployed on drill pipe and the cementing Port Collar was opened allowing the second stage cement job to be carried out. After displacement of the cement the operating tool was picked up to close and lock the Port Collar. A successful pressure test across the Port Collar confirmed this. All objectives were met; a world first was achieved for this combined operation. Since this first well was completed several other wells have similarly been completed. As a further development to this, a number of operators have expressed the need to have the MTM cementing port collar qualified to meet the requirements of ISO/DIS13679.2, which defines various ‘connection application levels’ (CAL), with CAL III now being the most severe.
Mitigate Drilling Risks in Highly Depleted Reservoir Fields by Intelligently Planning Well Trajectory for a CO2 Sequestration Project
Authors: Fang Zhi
Published: September 2011

A highly depleted gas field in the southern North Sea has been selected as a potential CO2 storage site. Data from drilling of production wells shows that wells experienced substantial tight spots, overpulls, cavings, mud losses, even pack offs, and considerable time was spent in reaming tight holes and circulating excessive cuttings. To mitigate the drilling risks for new CO2 injection wellbores, a geomechanical study was undertaken to understand the drilling issues and to quantify a practical mud-weight window.

The study used offset well drilling and wireline log data to derive field stresses, formation pressure, rock strength and elastic properties. A practical workflow was developed to characterise the interaction between pressure depletion and fracture gradient changes. In this particular case the results showed that the fracture gradient was as low as 9.3 ppg, and the wellbore collapse pressure in the overburden shale was highly dependent on the well trajectory. A vertical well could be drilled safely with a hydrostatic mud weight of ~8.6 ppg. A wellbore deviating at more than 65º would require mud weight approaching 9.3 ppg, the fracture gradient, to prevent wellbore failure. This leads to a tight mud-weight window for drilling management. If an operation mud-weight window of 0.5 ppg is required, the well inclination should be below 65º if it is planned towards the minimum horizontal stress Shmin orientation, or less than 45º if towards the maximum horizontal stress Shmax azimuth to mitigate drilling risks.

This paper describes a geomechananical workflow that assists in understanding the interaction between pressure depletion and fracture gradient changes from which it is possible to quantify a mud-weight window for safe drilling. The workflow description shows how the approach can help mitigate drilling risks and minimise drilling costs by optimising well trajectories and therefore play a significant role in the well planning and drilling management of depleted reservoirs.
Continuous Energy Efficiency and Green House Gas Emission Surveillance and Control
Authors: Cramer Ron , Goh KC , Iyer Mahesh , Wali Nnamdi , Spence Bill , Kessler Guus , Kanten Roy
Published: September 2011

The purpose of this paper is to document Shell's experiences and learnings in the effort to better track and reduce Green House Gases (GHG) and improve Energy Efficiency in our downstream manufacturing and upstream production operations. The paper is based on Case Studies from various Operating Units in Shell upstream and downstream operations, as well as outlining further development plans.

In Shell operations we seek to minimize GHG emissions by continuously monitoring, displaying and reporting associated Key Performance Indicators (KPI's) and quickly alerting operators of changes to trigger remedial intervention. Reduction of GHG emission is also achieved by improving cross validated and mass balanced tracking of our process streams. This ensures that manufacturing and production processes are operated efficiently and transparently.

Continuous GHG monitoring also allows automatic compilation of emissions by source which can then be automatically reported as part of the normal daily reporting cycle. The resulting emissions figures and associated KPI's are then prominently displayed in the Daily Production Report. The daily emissions totals are also stored and trended to flag more subtle and/or gradual changes. In this way GHG emissions data and performance information are made available to operations staff and management to facilitate awareness and corrective actions when appropriate.
Sensitivity Analysis for Dual Porosity and Dual Permeability Systems to Small and Large Scale Heterogeneities in a Naturally Fractured Carbonate Reservoir
Authors: Correia Manuel G. , Schiozer Denis J. , Santos Marcos S.
Published: September 2011

The best way to analyze the sensitivity of dual porosity (DP) or dual permeability (DK) systems is his interaction with small and large scale petrophysical features using a fine grid, since in a coarser scale, small scale heterogeneities are always integrate in an upscaled background matrix. Two significant petrophysical features in carbonate reservoirs were applied over a background matrix, defined by, low permeability but with separate vugs (SV) randomly distributed with high porosity and permeability: (1) tectonic fractures (nearly vertical) and (2) touching vugs (nearly horizontal), were defined as large scale fractures, with high permeability and low porosity. These features are combined and tested in two cases. In the first case, the flow is controlled by touching vugs and tectonic fractures. In the second case, the flow is controlled only by touching vugs. The two cases were tested with and without SV in the background matrix. In both cases, oil recovery factor (ORF) is higher in presence of SV. ORF in DK system is also higher than in DP system. In Case 1A, the ORF for the DP system is nearly equal to the case 1B, showing that the flow rate between matrix blocks is highly important in the presence of SV, leading to the necessity of a DK system application. Without SV, ORF is nearly equal for DP and DK systems thus disregarding the necessity of a DK system, given the higher flow simulation time. The front of injected water in second case is nearly horizontal and homogeneous in fracture component resulting in a higher flow rate between SV to fracture network. The heterogeneous front of injected water in first case reduces the significance presence of SV. This work gives a valuable sensitivity of DP/DK systems in the study of small and large scale heterogeneities.
Upscaling Technique Applied to Naturally Fractured Carbonate Reservoirs
Authors: Correia Manuel G. , Maschio Celio , Schiozer Denis J. , dos Santos Marcos S.
Published: September 2011

The purpose of this study is to develop an upscaling technique, applied to naturally fractured carbonate reservoirs, adjusting fracture blocks components and well indices according to our small scale fracture behavior using mini-models. Two significant petrophysical features of carbonate reservoirs were applied over a background matrix, defined by low permeability but with separate vugs (SV) randomly distributed with high porosity and permeability: (1) tectonic fractures (nearly vertical) and (2) touching vugs (nearly horizontal), were defined as large scale fractures, with high permeability and low porosity. These features are combined and tested in three cases, with the same background matrix. In the first case, the flow is controlled by high permeability thin facies and tectonic fractures; in the second case, the flow is controlled by touching vugs and tectonic fractures and in the third case the flow is controlled only by touching vugs. A fine grid cell size of 0.8x0.8x0.4 meters is used as reference for the upscaling method. All fracture grid blocks in coarser cell size (3×3×2 meters) were adjusted in order to calibrate the fracture direction according to our fine grid fracture behavior, combined with a well index adjustment. In order to isolate the matrix heterogeneities effects, the same fracture calibration procedure is applied to a homogeneous matrix using the same fracture network in order to validate the fracture upscaling. It was possible to adjust all reservoir parameters (field average and well pressure, oil recovery factor, etc.) and reduce the flow simulation time from days to a few seconds. With this methodology we can transfer small scale heterogeneities from different sources to a coarser scale without losing information.
Application of the Ultrasonic Technique for Monitoring and Measuring the Phase Fractions of Liquid-Gas-Solid Mixtures
Authors: Goncalves J. L. , Paiva T. A. , Carvalho R. D. , Venturini O. J.
Published: September 2011

In many industrial applications, especially in the oil industry, the requirements of multiphase flow measurement pose numerous technological challenges as it oftentimes involve harsh media, strict safety regulations, access difficulties, long distances, and aggressive surroundings. The fluids produced from oil wells most often emerge as a multiphase mixture of oil, natural gas, water, and a variety of solids (sand, hydrates, and asphaltenes). It is generally recognized that multiphase flow metering (MFM), i.e. measuring the flow rates of the individual phases in a multiphase flow, could have many advantages in terms of costs, layout of production facilities, well testing, reservoir management, subsea and downhole metering. In this regard, the ultrasonic technique has been receiving increasing attention in the past years because it is noninvasive, fast responding, and suitable for operation in harsh environments. In the present paper, initially a review is made of selected commercially available separation-type and in-line MFM systems; the multiphase flow parameters measured in each system and the techniques used as well as general comments regarding the system performance are provided. Next, ultrasonic attenuation and transit time data are presented for oil-continuous oil-air-sand and oil-air-water mixtures in steel pipes. A discussion is also presented on attempts to sort out the air and sand concentrations in water-air-sand mixtures from ultrasonic signals. It is hoped that the data presented will help establish the potential of the ultrasonic technique for use in MFM systems in combination with or replacing specific instruments already in use.
Unique Axial Oscillation Tool Enhances Performance of Directional Tools in Extended Reach Applications
Authors: Al ali A.. , Barton S.. , Mohanna A..
Published: September 2011

The effect of having an axial oscillation generator tool (AGT) in the drill string has been demonstrated to be the difference between the premature termination of drilling a section and successful completion of the section to planned TD. The AGT tool has traditionally been used in commercial applications where sliding with steerable motors has been problematic.

Axial oscillation in the drill string is generated through a series of pressure pulses coming from one part of the AGT. The pressure pulses act on the pump open area of the shock tool, generating the axial motion required to reduce friction, improve the weight transfer to the bit, reduce reactive torque (and thus overall) downhole torque. The hydraulic vibration also enhances the performance through reducing friction. Combined together, the hydraulic vibration and the axial vibration have proven extremely effective in reducing friction and improving weight transfer with steerable motor assemblies. This had led to increase step-out capabilities, improved tool face control, reduced vibration, and higher penetration rate.

This paper provides an overview of the tool technology and application with motors. However, it also focuses on expansion of the tool application with both conventional rotary and also rotary steerable BHA’s. Test results discussed include; A study on rotary drilling with AGT to evaluate and quantify improvement in weight transfer to the bit, revealing significant improvement in DWOB and reduced torque-at-bit.Overview of the compatibility of the AGT with rotary steerable system (RSS) and MWD tools, in particular the dynamic of the AGT which influences the weight transfer. Significant improvements in drilling performance are revealed when combining AGT and RSS.

Case studies are included, displaying the breadth of benefits with the AGT with all forms of drive systems (rotary, motor, and RSS).
Heavy Duty Wireline Fishing Operations in a HP/HT Sour Gas Well: A Case Study
Authors: Purwagautama Gustioro , Afandi Idi Yusup , Rachman Syahriza Ghany , Vincent John M.
Published: September 2011

HP/HT gas wells, especially those in South Sumatra, Indonesia, present many challenges to exploitation operations due to a 408°F bottomhole temperature, a 10,500psi bottom hole pressure at some 11,000ft, and sour gas components of 34% CO2 and 100 – 200ppm H2S.

During the final stages of the completion of one such well, after setting the production packer a wireline run was made with .108″ slick line to recover the plug body from the seating nipple at 11.406ft. While pulling out and with the plug at 6000ft. the well became live without warning, blowing the tool string up the hole and, to contain the well, the drilling BOPs were closed shearing the landing joint which in turn closed the sub surface safety valve. Subsequently the well was successfully completed and prepared for wireline fishing operations.

The wireline fishing operation went on for several days using .108″ wire, during which 45 runs were made with the recovery of only approximately 550ft of wire and so it was decided to call in heavy duty wireline fishing (HDWF) expertise to review the situation and make recommendations as to how to proceed. This resulted in a commitment being made to mobilize personnel and equipment from Aberdeen and the Middle East to carry out the required operations. In the meantime a total of 11 further runs were made in the well using coiled tubing which resulted in recovery of the upper part of the tool string and some additional wire. Fishing operations were recommenced using 7/32″ Supa 75 braided cable with two two/man crews providing 24 hour operation and a project leader located at the clients office to provide for direct liaison. After a total of 17 runs over 6 days of continuous operation, the fish was completely recovered and the well made ready for production.

In this paper the authors will review the situation that was faced, the remedial work done to complete the well, the early fishing operations and the subsequent input of HDWF expertise. They will conclude with a detailed account of the successful HDWF operation – an excellent example of how careful planning, experienced personnel, dedicated project management and a collaborative relationship between the client and service company can lead to a successful outcome.
The Application of Heavy Duty Wireline Fishing Techniques Retrieves Wellbore Obstruction and Allows Well to be Plugged and Full Integrity to be Regained
Authors: Flett C. , Macaula R. , Vincent J. M.
Published: September 2011

This case study will examine the removal of an obstruction in Well BC-14 on the Shell operated Brent Charlie platform. Obstructing access to the well was a 3.6″ OD wireline roller bogie cutter, 6600ft of 0.125″ wire, a slickline tool string and a 4-1/2″ PES HE-3 bridge plug complete with setting tool. The fish had been in the well for three and a half years with the condition of the wire lost down hole undetermined, in addition the well had tubing to 'A' annulus communication. The operational objective was to remove all obstructions from the well in order to allow access to set a plug and secure well integrity.

This paper will detail the operation while highlighting the limiting factors and challenges overcome as well as demonstrate how the use of Heavy Duty Wireline Fishing (HDWF) equipment and downhole tools, in conjunction with detailed planning, provided a cost effective solution to alternative options such as Coiled Tubing.

The successful utilization of HDWF techniques were applied with no lost time or safety incidents and resulted in the complete recovery of well obstructions, allowing the well to be plugged and its' integrity to be regained.
Cased-Hole Multistage Fracturing: A New Coiled-Tubing-Enabled Completion
Authors: Ravensbergen J. E.
Published: September 2011

Multi-stage proppant fracturing of horizontal wells has changed the economic landscape of the North American Oil and Gas Industry. Open-hole ball drop completion systems, are an economic solution for many operators, however alternative completions systems are emerging into the marketplace. This paper will describe a novel CT actuated, predominantly cased hole, CT Frac Sleeve completion.

This paper will explain how it works, and how operators are taking advantage of several new capabilities not available in other completion systems. The new capabilities that will be described include better placement control of each treatment and an unlimited number of treatment stages resulting in better drainage of the reservoir.

In addition, this paper will describe how CT and its bottom-hole assembly are not only required to sequentially open each of the CT Frac Sleeves, for each stimulation treatment, but add additional value to the system. How CT enables quick recovery from screen outs, freeing the fracture treatment process engineer to optimize the treatments without the risk of large financial penalties. Further how CT is used to accurately measure the bottom hole pressure during the treatment, also aiding the engineer to optimize the stimulation treatment, ultimately delivering a better stimulation treatment and improving the productivity of the reservoir. Finally, the paper will discuss how the CT BHA has contingent capabilities, as it is equipped with a sand jet perforating device.
Visualization of Natural Convection Flow of (Sub-) and (Super-) Critical CO2 in Aqueous and Oleic Systems by Applying Schlieren Method
Authors: Khosrokhavar R. , Elsinga G. , Mojaddam A. , Farajzadeh R. , Bruining J.
Published: September 2011

Efficient storage of carbon dioxide (CO2) in aquifers requires dissolution in the aqueous phase. Firstly, the volume available for gaseous CO2 is far less than for the CO2 to be dissolved in the water initially present in the aquifer. Secondly, the partial molar volume of CO2 in the gas phase is about twice as large as the partial molar volume of CO2 in water, meaning that storage in the water phase leads to less pressure increase per amount of sequestered CO2. Transfer of CO2 from the gas phase to the aqueous phase would be slow if it were only driven by diffusion. However, dissolution of CO2 in water forms a mixture that is denser than the original water or brine. This causes a local density increase, which induces natural convection currents accelerating the rate of CO2 dissolution.

This study presents a set of high pressure visual experiments, based on the Schlieren technique, in which we observe the effect of gravity-induced fingers when sub- and super-critical CO2 at in situ pressures and temperatures is brought above a liquid, e.g., water, brine or oil. A short but comprehensive description of the Schlieren set-up and the transparent pressure cell is presented. The initial experiments are confined to bulk-phase situations, i.e., in the absence of a porous medium. The experiment is able to demonstrate the initiation and development of the gravity induced fingers. The concentration gradient is high near the gas-liquid interface. The experiments show that natural convection currents are weakest in highly concentrated brine and strongest in oil. The set-up can screen aqueous salt solutions or oil for their relative importance of natural convection flows.
Influence of Downhole Fluid Behavior Changes on Slickline Operations in Burgan and Magwa Oil Fields, Kuwait
Authors: Bouhanna M.
Published: September 2011

Slickline down-hole flow control devices are always subjected to forces created by differential pressure where they are setting in tubing.

The standard practice for retrieving a flow control device (e.g. Plug from landing nipple) is to equalize pressures prior any retrieving attempt.

Slickline operators are always focusing on a mechanical surface wire manipulation of down-hole tools and surface pressure gauge to monitor equalizing pressure, while they overlook the effect of influential down-hole conditions such as: fluid level, fluid gradient, gas segregation and phase changes which based on we can calculate and determine the actual equalizing pressure.

In some cases, the equalizing pressure could not be completed properly due to reservoir fluid behavior change while operating or sometimes equalizing ports might be plugged, therefore any retrieving attempt can lead to an unknown events such as: Slickline tool string blown up due to differential pressure during retrieving plug from a landing nipple.Slickline tool string blown up due to huge differential pressure created by asphaltenes bridge plug formation in the tubing.Slickline toolstring blown up during a flowing gradient survey with a portable well test due to choke changes.Slickline plug stuck in landing nipple, due to the hydrostatic pressure head acting on the plug.Collection of a non representative single phase bottom-hole sample due to downhole phase change.

This paper will discuss the newly developed procedures (best practices) resulting from a meticulous study of downhole fluid behavior changes and their influence on slickline operations. These best practices allow slickline to reduce this risk to a controlled level and provide a high service performance at low cost. Case histories from Burgan & Magwa oilfields will be used to illustrate overlooked slickline job failure root causes and how best practices contribute in providing innovative low cost service options.
Success from Subsea Riserless Well Interventions
Authors: Fjærtoft L. , Sønstabø G.
Published: September 2011

This paper describes how Statoil, over a period of 10 years, have qualified and implemented Subsea Riserless Light Well Intervention (RLWI) applications as their primary means of intervening in subsea wells. The paper will also demonstrate the value of RLWI in relation to the company's Increased Oil Recovery (IOR) goals.

Subsea wells represent the area where least well intervention work has been done, and where the biggest practical and technical challenges also lie. Hence less oil is recovered from subsea completed fields than from those with fixed platforms. RLWI is a cost effective intervention method that allows an operator of subsea wells to increase production and optimize utilization of vessels and rigs.

Statoil is a leading exponent of RLWI services, utilizing two specialized and modern vessels on full year contract. A third vessel is currently being considered. The total RLWI activity for 2010 was 671 days, spanning a total of 32 different jobs. This paper will describe the development of these applications from 2000 until today covering a total of 125 individual operations. Statoil has 34 subsea fields, of which 32 are on the Norwegian continental shelf with a total of around 460 individual wells. Light Well intervention has been performed on 11 of these fields. Experience so far indicates that there are no limitations on equipment regarding interface to subsea templates.

In this paper the contract philosophy for these services will also be discussed. Further on, the agreement between the different production assets for sharing of resources will also be described. The technical achievements and limitations will be listed and described. Then the needs of the future will be described and prioritized.

Finally, the economic benefit and contribution of introducing Riserless Light Well Intervention will also be highlighted. The following three conclusions on RLWI will be elaborated on in this paper: Improves HSE in subsea well interventionsImproves recoveryIntervention cost is cut by more than half compared with anchored rigs and riser systems
Installation of Velocity Strings (VS) Without Loading-Killing the Well
Authors: Chavez Manuel
Published: September 2011

Installation of a small diameter velocity string (VS) is often necessary in tight gas wells to resolve liquid loading problems. Coiled Tubing (CT) is commonly used as a velocity string conduit due to safe live-well installations and speed. A technique is being applied in which wells are cleaned out with coiled tubing which is then hung off as a velocity string in one trip. The wells are left flowing during the entire operation so that the wells are not loaded up completely and off production after the operation. A new coiled tubing hanger was designed and utilized such that two well control barriers are maintained during the operation. This paper will review the equipment package and the installation process.
Hurricane Contingency for Stuck Coiled Tubing: Preparing for Platform Evacuation and Allowing a Safe Recovery Maurice, Louisiana, North Gulf Coast
Authors: Torres Carlos , Creppel Carl , Kelm Charles H. , Moorkamp William , Cottingham Kris
Published: September 2011

Operations in the Gulf of Mexico (GOM) are affected during the months of June through November by the weather, as hurricanes are generated and come into the GOM, creating the need to plan abandonments to avoid harm to any personnel, environment and minimize damage to facilities. During June 2010, while executing a scale clean out operation on a platform with 1.25″ coiled tubing (CT), the pipe got stuck. After 11 days of troubleshooting, it was required to evacuate the platform due to a hurricane that was approaching. A management of change was developed to safely secure the CT string at surface, which would allow for abandonment while maintaining well control (WC). During this process three options were analyzed: the first option was to add additional support to the injector head(IH) jacking frame and leave the pipe stabbed in, this option was rejected because it would not guarantee WC in the event that the storm takes down the IH.

The second option was to secure the CT with the Blow Out Preventers(BOP) then shear it, and rig down the IH. This Approach provided WC, but it created additional risk and limitations when resuming the retrieval operation after the storm. The third option was to secure the CT at the BOP and cut it above the IH. With the removal of the IH, this would leave the section of pipe that was previously across the chains and riser free above the BOP. An appropriate valve would then be connected to the CT stub end, for WC.

Furthermore, by sliding a riser section over the CT stub and making up a gate valve and night cap would minimize the exposure to the storm. Finally, the riser could be secured to the deck. After analyzing available options, the third alternative was recommended and approved by the BOEMRE; as this option addressed WC and allowed safe recovery by re-stabbing the pipe back into the IH, and rigging up the required equipment to proceed with the pipe recovery operation.
Optimization of Operational Time and Workover Resources With the Alternate Use of Coiled Tubing and Pulling Unit for Well Abandonment
Authors: Pando A. , Silva L. , Lopez B. , Cardona G. , Acevedo O.
Published: September 2011

Casabe Field is a mature oil field located in the Mid-Magdalena Valley basin in Colombia, with over 60 than years of production. For the last 25 years it has been waterflooded using a five-spot injection pattern. In 2004 Ecopetrol and Schlumberger initiated a technological alliance aiming to increase the recovery factor and to incorporate new reserves. From an integrated work the project defined an aggressive drilling, completion, workover operations to convert old water injectors into multi-zone selective completion injectors and the abandonment of damaged wells campaign to optimize the waterflooding patterns.

The workover program reached its highest activity peak of from 2008 to 2009. This increment brought the need to perform several well abandonments to avoid interference with the new injector wells. The abandonments also proved to be a main challenge of the campaign because of the well status complexity as severe casing restrictions, fishing, abnormal pressures, and reduced surface location area.

A new methodology to optimize workover resources was developed based on alternating the use of a Coiled Tubing combining a Pulling Unit. This methodology enabled the workover in wells where workover rigs had serious downhole and surface limitations. From 2009, 96 wells were abandoned, 52% of them applying the method that combines both units. The methodology has generated so far 181 days of Workover rig time in savings, therefore allowing the rigs to complete more than 235 wells by the end of 2009, complying with the overall project program contributing with an incremental production of 5000 BOPD. In addition, this methodology to abandon well has generated alone savings of 1.5$MMUSD from the initial CAPEX.

This paper will describe the agile well abandonment methodology combining Coiled Tubing and Pulling Units in a highly efficient, economical way, and complying with HSE standards and regulations allowing its application in any other oilfield.
Ultrasound Logging Techniques for the Inspection of Sand Control Screen Integrity
Authors: Hyde-Barber C. , Weighill G. T. , Tymons T. R. , Solberg M. , Helland A. G.
Published: September 2011

A significant proportion of worldwide production comes from sand prone reservoirs and is increasingly dependent upon the performance of sand control completions. However, sand control screens can fail which may lead to lost production or untimely abandonment of the well. In many cases remedial action may be possible, but the advanced design of sand control devices presents a considerable challenge to many inspection techniques, leading to a gap in understanding the failure mechanism. This paper documents the application of an innovative ultrasound-based technology for the inspection of sand control screen failures, including results and conclusions derived from an extensive testing program.

The objective of the testing was to prove the feasibility of using phased array ultrasound technology to locate sand entry points and assess the integrity of the screen in the down hole environment. Specifically, the aim was to assess the ability to provide integrity information from the internal surface of the base pipe to the outermost surface of the screen. During testing, several types of sand control screens were methodically damaged, simulating the defects observed in screens recovered from sand producing wells. The damaged screens were deployed in a test well and logged with a wireline setup.

The data indicates that damage resulting in enlarged base pipe perforations is detectable and the internal surface of the base pipe imaged in all screen types. Dependent upon the screen type, the ability to detect damage to the external layers of the screen, without any base pipe damage, has been demonstrated. In conclusion, in a test well environment the application of phased array ultrasound has been validated for the investigation of damaged sand control screens.
Revolutionary Matrix Stimulation Process in Offshore Mexico Using Coiled Tubing Equipped With Optical Fibers (CT-EOF) and Distributed Temperature Survey (DTS)
Authors: Garcia S. , Franco E. , Gerardo M. , Davila L. , Ortiz B. , Castillo M. , Miranda R. , Perez J.
Published: September 2011

During the last 30 years, in offshore Mexico, matrix stimulation treatments were designed and executed around pumping large volumes of fluids by a "bullheading technique," which comprised multiple stages of pre-flushes, acids, and solvents without adequate control of placement. The objective of these matrix stimulation treatments in the Ku-Maloob-Zaap carbonate formations fields is to remove drilling-induced damage and achieve maximum well productivity. This is a challenge because this formation is naturally fractured and presents high permeability, around 4-5 Darcies. The "bullheading technique" has been proven to be inefficient because the evaluation logs have shown non-uniform stimulated intervals.

Recently, coiled tubing (CT) operations adapted a new procedure to improve the stimulation treatment's placement technique. However, the biggest concern was to determine if the chemical fluids had correctly stimulated the target zones. The initial solution was achieved by pumping radioactive tracers with the chemicals during the stimulation and an additional CT run performed to take a gamma ray (GR) log. This procedure has proven to be inefficient and time consuming.

For first time in offshore Mexico, the innovative technique of combining coiled tubing equipped with optical fibers (CT-EOF) and distributed temperature survey (DTS) to acquire and record pressure and temperature data—which is compared with petro physical data in real time—to decide selective placement of chemical fluids in target zones, was implemented in a completed oil producer cased hole well in Campeche Bay. This innovative technique reduced operational time and eliminated the additional CT run while optimizing the placement of the stimulation fluids for improved well productivity. The information obtained from the DTS allowed informed decisions to be made on alternative lifting methods to improve the well productivity performance for this well.

The job design, execution, and post-treatment evaluation of a matrix stimulation treatment in well M-432—where CT-EFO and DTS were combined—will show how the operation was optimized. In addition, the comprehensive analysis from DTS data was used to optimize placement of the stimulation treatment, the evaluation of effectiveness of the matrix stimulation treatment, the analysis used to identify the well productivity problem, and the benefits this new technique offers in the Ku-Maloob-Zaap carbonate formation.
3D Borehole Model for Evaluation of Wellbore Instabilities in Underbalanced Drilling
Authors: Roshan H.. , Rahman S. S.
Published: September 2011

Underbalanced drilling (UBD) has been used in the oil industry to avoid formation damage, reduce lost circulation and increase the rate of penetration. Underbalanced drilling in incompetent rocks, however, poses severe borehole stability problems. Numerous models have been developed to predict the time dependent wellbore collapse during drilling, in particular underbalanced drilling. Experience shows that these models require data that are hard to obtain and without these data results become unreliable. A three dimensional wellbore model has been developed at university of New South Wales to help drilling engineers determine the optimal mud composition and a range of bottom hole pressure for underbalanced drilling. The concept of thermodynamics of irreversible processes, consolidation and elastoplastic constitutive law are employed to predict the temperature and ion distribution, pore pressure and effective stresses around a borehole. These data sets can be used as input to borehole stability analysis. From the results of this study it was revealed that the effect of plasticity on stress relaxation around the wellbore is a major concern during underbalanced drilling. This relaxation especially in hoop stresses can lead the wellbore to collapse. The results also showed that the size of plastic zone depends not only on the horizontal in-situ stresses but also on the vertical in-situ stress.
Innovative Coiled Tubing Equipment for Successful Temporary or Permanent Zonal Isolation
Authors: Al-Harbi Mesaad S. , Said Rifat , Haldar Surajit , Burov Anton , Kharrat Wassim , Ahmed Danish
Published: September 2011

The well stimulation and water shut off (WSO) job in the carbonate reservoir of Ghawar field in Saudi Arabia is becoming increasingly challenging, considering the complex well completion. Many challenges are therefore encountered during coiled tubing (CT) interventions when trying either to permanently shutdown water production or to temporarily isolate the water zone to stimulate the oil intervals. In fact, the lack of real-time bottom-hole control of mechanical or chemical diverters caused these jobs to fail with conventional CT strings, which eventually called for costly solutions using workover rigs.

This paper describes multiple shortfalls of previous WSO and matrix stimulation jobs, and how this trend is reversed after the emergence of the fiber optic enabled CT (FOECT) string with real-time downhole measurement sensors.

The permanent zonal isolation utilizing an inflatable packer with cement plug is now possible with greater accuracy and enhanced success ratio even in wells with complex completions. The availability of a real-time casing collar locator (CCL), bottom-hole temperature (BHT) and differential pressure readings enables adequate control of packer setting depth and inflation, and optimization of the cement design and its injection.

The temporarily zonal isolation using chemical diverters can now be assessed real-time with the Distributed Temperature Survey (DTS). The stimulation fluids will not be pumped unless the isolation of the water zone is confirmed. The CT acid job can be now optimized by eliminating the risk of losing acid into the water intervals and by ensuring a uniform acid coverage across the oil zones with DTS.

This method was validated with the wireline log run just before the CT job. Challenges, design, execution and results of zonal isolation interventions with both conventional CT and FOECT are detailed in this paper to demonstrate that this type of CT job becomes more successful with the FOECT.
Survey of More than 1,000 Fracture Stage Database with Net Pressure in the Barnett Shale, Part 2
Authors: Shelley Robert F. , Lehman Lyle V. , Shah Koras
Published: September 2011

This paper is a continuation of SPE 138277, which studied a database of microseismic data and compared the information with net pressure. This second phase focuses on creating a completion tool that provides completion and stimulation designers a better guideline to generate quality or effective design.

The data was clustered using Self-Organizing Mapping (SOM) techniques to associate treatments with similar characteristics. These techniques included proppant type, injection rate, volume of frac fluid and proppants, perforation interval spacing and other key factors that shape a completion design to effectively stimulate a targeted volume of shale reservoir rock.

The completion workflow was developed through several data-mining techniques while using sound engineering observations. SPE 138277 unveiled the theory of "Managed Fracture Complexity" by illustrating the impact of perforation spacing on stimulated reservoir volume in principally isotropic shale such as Barnett. This paper will extend that concept toward creating an optimized design.