bluuebunny/crossref_metadata_2025 huggingface dataset:
Physico-Chemical Characterization of Non-Aqueous Colloidal Gas Aphron-Based Drilling Fluids
Authors: Shivhare S. , Kuru E.
Published: February 2011

The colloidal gas aphron (CGA) based drilling fluids are designed to minimize formation damage by blocking the pores of the rock with microbubbles, which can later be removed easily when the well is open for production. Aphrons behave like a flexible bridging material and form an internal seal in a pore-structure.

Size and concentrations of the bridging materials are very critical to the fluid's ability to seal the high permeability zones. Proper sizing of the microbubbles with respect to pore size distribution is essential for developing an aphron drilling fluid with effective sealing ability. The physico-chemical properties (i.e., viscosity, density, fluid loss, etc.) of the CGA base drilling fluids also need to be understood in order to drill with these fluids more effectively.

Aqueous CGA based drilling fluids systems have been fairly well characterized and successfully implemented in high-angle and horizontal wells drilled in low permeability as well as highly depleted reservoirs. Effectiveness of pore blocking by colloidal gas aphrons is expected to be improved even more, if we can replace water with non-aqueous base fluid such as mineral oil.

An experimental study has been conducted to determine the effect of base fluid composition (i.e., surfactant and polymer concentration) on the microbubble size and stability. The surfactant and polymer concentrations required for optimum formulation of mineral oil base CGA drilling fluids were determined.

The physico-chemical properties of non-aqueous CGA drilling fluids are also investigated. The results of rheology, filtration loss and density measurement tests are also presented.
Experimental Investigation of Solvent Co-Injection in Vapor and Liquid Phase To Enhance SAGD Performance
Authors: Li Weiqiang , Mamora Daulat D.
Published: February 2011

Coinjecting solvent with steam under a steam-assisted gravity drainage (SAGD) process to reduce the required steam amount for heavy oil production has gained importance in recent years. The objective of this experimental study was to investigate the drainage mechanism for solvent co-injection in the vapor and liquid phases to improve production performance.

A 2D cross-sectional low-pressure scaled physical model was constructed. The model represented a half-symmetry crosssection of a typical SAGD drainage in the Athabasca formation. Using an infrared camera, we visualize and record expansion of the steam chamber and temperature distribution. The fluid injection rate, pressure, and temperature, and produced liquid volumes were also recorded.

The results show that the relative condensation time of solvent and steam results in different production performance. Solvent delivered in the vapor phase to the entire fluid interface reduces the bitumen viscosity along the whole vapor chamber boundary, but it may build a thick gas blanket that may reduce the heat transfer from the high-temperature vapor chamber to the surrounding low-temperature bitumen. Co-injecting a suitable multi-component solvent mixture, including a liquid solvent, can enhance the production performance by altering the condensation dynamics of the light hydrocarbons.

The conclusions from this study can be used to design suitable solvent mixture and coinjection strategies to deliver higher production rate, higher recovery factor with lower cumulative steam required to oil ratio (CSOR), and lower cumulative energy required for oil production (CEOR) from SAGD performance.
Upgridding Method for Tight Gas Reservoirs
Authors: Kelkar Mohan , Atiq Mustafa
Published: February 2011

Low permeability sandstone reservoirs in western US produce gas and water. Their geologic history indicates the development of non primary drainage equilibrium. Hence, one does not observe transition zone but trendless variation in multiphase fluid saturations throughout the formation. These varying multiphase fluid saturations will affect the effective permeability available to gas and water phases. Since the flow potential of a well is directly related to effective permeability, we propose a novel upgridding method to combine grid blocks having similar effective permeabilities which will implicitly take into account upscaling of multiphase fluid saturations in these tight gas systems.

Our algorithm groups vertical layers in a way such that the heterogeneity loss of an appropriately defined static property is minimized within layers. We define this static property of a grid block as the product of its net volume, its absolute permeability and relative permeability available to a phase within that grid block. The upgridding approach is essentially a sequential coarsening algorithm that starts from a fine scale model and merges the two adjacent layers that results in a minimum heterogeneity loss of defined static property.

To determine the optimum number of up-gridded layers for efficient numerical flow simulation of these detailed geological models, we define criteria such as removal of heterogeneity from a model at a particular coarsening step and design factor which will help preserve the critical level of heterogeneity. We compare our upgridding method with proportional upgridding and traditional variance based methods for synthetic and field cases of tight gas reservoirs, and the results demonstrate that our proposed layer combinations can better capture dynamic flow behavior of the fine scale model.
Design Optimization of Slotted Liner Completions in Horizontal Wells of Mumbai High Field
Authors: Kumar Avinav , Srivastava A. K. , Kumar Ravi
Published: February 2011

An efficient and cost-effective completion is very critical in the mature brownfield of Mumbai High. Horizontal and multilateral wells are strategic completions in this oil reservoir because of their high productivity and larger drainage area. This paper deals with design optimization of slotted liner for horizontal wells in Mumbai High field of India.

A good horizontal completion must maintain the mechanical integrity of the wellbore without posing a significant flow restriction. In this respect, slotted and perforated liners are cost effective solutions in horizontal wells because they provide uniform reservoir drainage, wellbore stability and control of solid production. A slotted liner completion is preferred, because it results in better solid control and lesser flow convergence. However, the compounded effect of formation heterogeneity and formation damage on pressure loss is severe in these completions. A good design is essential to minimize pressure loss due to flow restrictions and to maintain the long term productivity of well.

The major challenge is to have an optimum slot size and geometry that minimizes slot plugging and near wellbore flow convergence losses. A keystone slot design with consideration for convergence loss is arrived to address this problem. The effect of parameters such as slot size and slot density on flow convergence pressure loss was taken into account for design optimization.

This paper covers the design, optimization and application of slotted liner completions with an objective to address solid control, completion economics, well productivity and long term well performance.
Maximizing the Oil Recovery through Immiscible Water Alternating Gas (IWAG) in Mature Offshore Field
Authors: Tewari Raj Deo , Riyadi Slamet , Kittrell Charles , Kadir Farihan Bt , Bakar Mohamad Abu , Othman Tg Rasidi , Banu Nazrin
Published: February 2011

This paper discusses an enhanced oil recovery study of a multilayered mature offshore oil field in Baram Delta. Multiple reservoirs of the field have varying rock and fluid properties.The shallower accumulations contain oil of low API gravity of 19º with very low solution gas-oil ratios, while API gravity increases with depth to 24º in middle formations and 37º in the deepest sands. Upper sands are poorly consolidated with resultant high porosity and permeability. Most of the reservoirs are undersaturated. Initial field development comprised primary depletion with gas lift through vertical and directional wells - mostly dually completed. Field development strategy implemented measures like gravel packing wells to meet the challenges and possible problems during the course of field exploitation.

Field performance indicates that the current development strategy and practice may lead to moderate recovery lower than average recovery in Baram Delta fields through primary production. Detailed reservoir characterization has been carried out to capture the reservoir heterogeneity and multiple realizations have been made to understand the major uncertainties of the field. Screening studies for maximizing the recovery from the field suggests gas based EOR techniques may find application. The EOR method of Water Alternating Gas injection (WAG), both immiscible and miscible, is gaining significant interest for improving the oil recovery in offshore fields. The improvement in recovery due to WAG injection is attributed to contact of the upswept zones and modification of residual oil saturations and targeting the attic oil. The advantage of the process is that combination of water and gas injection provides the improved displacement efficiency of gas flooding with improved macroscopic sweep efficiency due to water injection. The result is improvement in recovery compared to separate gas or water injection. Also three phase flow (oil, water and gas) is better in displacing the residual oil compared to two phase flow water and oil or gas and oil.

Parameters which are critical for impacting the WAG enhanced oil recovery process are studied thoroughly. These parameters include WAG ratio, injection rates, cycle, well spacing, sweep efficiency and conformance control. WAG is planned for AB, C, D, and EF reservoirs which have low to moderate recovery. The study suggests that improving the well spacing and proper injection volume provides improvement in recovery factor of the order of 8-10%. The paper also discusses the mechanism of the process through mechanistic modeling and laboratory studies for injection water compatibility, rock- fluid interaction, gas mobility control using Nanofluid/Foam which is expected to provide the better sweep and upside potential.
Successful Applications of Expandable Sand Screen in Persian Oil Fields, Part 2
Authors: Deilami Fatemeh , Salehi-Moorkani Reza , Ghasemzadeh Amir
Published: February 2011

In some Persian oil fields hydrocarbon recovery is mainly from sandstone reservoirs and sand production is a major problem in these fields. Main reason of sand production in these reservoirs is due to unconsolidated sandstone layers. The common method to decrease this problem is achieved by installing mechanical sand control systems. Previously, some techniques of sand control have been used in Persian oil fields, such as gravel packing, slotted liner and chemical consolidation. The results which have been obtained through these methods are not remarkably good enough in some cases.

Expandable sand screen (ESS) is a new technique in sand control that can result in lower skin and consequently improves reservoir inflow performance. Field tests in various conditions have shown very satisfactory results in both open and cased hole applications. This paper will discuss economic aspects of ESS and analyses well pressures. In addition it provides ESS comparison with other sand control systems through real cases and well modeling. Finally, it talks about the candidate selection step and its significance on ESS performance.
Well Treatment Fluids Prepared With Oilfield Produced Water: Part II
Authors: Li Leiming , Ezeokonkwo Chucks I. , Lin Lijun , Eliseeva Ksenia , Kallio Wade , Boney Curtis L. , Howard Paul , Samuel Mathew M.
Published: February 2011

As fresh water becomes more expensive, production and service companies have been trying to use low-quality water such as produced water. Broadly defined, produced water may include any unclean oilfield water that often contains bacteria and high salinity/hardness. Preparation of polysaccharide-based well treatment fluids with produced water frequently results in poor viscosity even when the water is pre-treated with biocides, possibly due to the polysaccharide degradation by bacterial enzymes in the water. This paper presents our continuous success in solving the produced water reusing problems, and discusses the chemistry and case histories of the treatments in North America.

A new fluid stabilizer has been developed recently that dramatically extends the lifetime of polysaccharide when used in produced water containing bacteria, possibly because the stabilizer denatures bacterial enzymes. This stabilizer has made it possible to prepare a variety of treatment fluids with produced water.

Since its introduction, the fluid stabilizer has brought greatly enhanced performance for the borate-crosslinked polysaccharide fracturing and sand control fluids, as reported in SPE 124212. In this paper we continue to explore the new and broader applications of the stabilizer. The polysaccharide fluids with metal crosslinker have been successfully prepared with the stabilizer-treated produced water. The fluids can endure higher temperatures. At the same time, the fluid pH can go below 4, making it possible to energize the fluids with carbon dioxide. The stabilizer has also been used to treat water contaminated with high counts of bacteria, which in turn has been successfully made into crosslinked polysaccharide fluids with improved high-temperature stability.

The expanded applications of this fluid stabilizer have further lowered the operating costs for the production and service companies. This new technology has also contributed to the environmental improvement by saving fresh water and recycling produced water in oilfield operations.
Testing Methodology for the Preliminary Assessment of Mechanical Performance of Materials for Expandable Applications
Authors: Bufalini A. , Morana R. , Nice P. I. , Nasvik H. , Kjørholt H. , Bailey B. M. , Adam M. K. , Jiral D. G. , Ross R. C. , Smith R. C.
Published: February 2011

While the introduction on the market of expandable casing has undoubtedly been successful, the full potentiality of this technology seems not yet accomplished. Uncertainties related to the reliability of expandable applications prevent the full exploitation of expandable tubular technology to reduce well construction costs and improve well productivity.

One key limiting factor is the incomplete knowledge of the mechanical performance after expansion of the materials used for the expandable casing. This is partially due to the lack of industry consensus on the most appropriate methods to measure post-expansion material performance. Also constraining is the availability of materials expanded by the methods used downhole.

As a consequence, an extensive experimental program was started by Statoil with the goal of identifying suitable testing methodologies to predict the post-expansion mechanical properties by analyzing a material only in its initial conditions. This paper describes the testing methods developed and compares the results obtained on as received materials with the results of tests carried out on the same materials after laboratory expansions performed specifically for this program.

The results show that it was possible to obtain a good estimate for post-expansion material properties like tensile yield, compressive yield and strain aging effect, enabling the prediction of post-expanded pipe performance ratings. The calculations of post-expanded collapse pressure were then compared with the results of actual collapse tests on expanded samples, showing good correlation both for expanded material and, when appropriate, for expanded and aged material. A procedure to perform a quick assessment of materials for expandable applications, based on the tests identified, is then proposed and discussed.
Real-Time Reservoir Characterization and Geosteering Using Advanced High Resolution LWD Resistivity Imaging
Authors: Al-Musharfi Nedhal , Bansal Radhey , Ahmed Mahbub , Kanj Mazen , Morys Marian , Conrad Chris , Chemali Roland , Lotfy Amr , Bayrakdar Mohammed , Parker Tim
Published: February 2011

A recently introduced azimuthal resistivity LWD imaging tool has been upgraded with advanced high resolution sensors that are capable of differentiating reservoir and borehole features down to a size of 0.4 in. when drilling in well consolidated formations. The high vertical and azimuthal resolution, along with 100% borehole coverage, yield an image quality comparable to that of wireline service for applications that include fracture characterization and formation evaluation.

This paper describes a field test of the high resolution tool in 5 7/8" and 8 3/8" holes in Saudi Arabia and shows the application of LWD images for estimating carbonate reservoir producibility involving the characterization of secondary porosity. The LWD imager provides significant economic and logistic benefits, especially in slim horizontal sections; in addition, it can identify fractured zones with mud loss potential shortly after penetration. The real-time resistivity provides a good basis for accurate dip calculation and geosteering in general.

In its default configuration, the high resolution tool is equipped with six high resolution sensors arranged in two rows. One of the benefits of the multi-sensor configuration, demonstrated by the field test, is the ability to validate the image quality by comparing data from various sensors. Another benefit is the depth correction achieved by correlating images from identical sensors located at various depths.

The paper also discusses the fundamental principles behind high resolution resistivity imaging in conductive mud and makes extensive use of modeling techniques to characterize the sensor performance in various practical situations.
Comparison of Chemical and Hysteresis CO2 Trapping in the Nugget Formation 2
Authors: Behzadi S. H.
Published: February 2011

The Moxa Arch Anticline is a regional-scale northwest-trending uplift in western Wyoming and it has been chosen for CO2 capture and storage. The Nugget Sandstone is a deep saline aquifer that has been a candidate for CO2 storage. In this paper we compare the amount of mineral and solution trapping in comparison with dynamic hysteresis trapping based on compositional simulation. To the best of our knowledge this is the first paper to computationally assess the chemical trapping in the Nugget formation and to compare these three trapping mechanisms against each other.

Reaction-path and kinetic modeling of CO2–brine–mineral reactions in the Nugget formation was investigated to probe the factors that affect capacity for CO2 chemical trapping. The geochemical simulation of this system was explored in order to assess how mineralogy might change and the relative importance of mineral and solution trapping phenomena through time. Mineral trapping is simulated with both GWB and GEM-GHG. The maximum mineral trapping is 5 g of CO2 per ton of reacted rock, and solution trapping is 3.47 g/kg rock. In comparison, a recent computational study of the Rose Run sandstone, Ohio indicates a much higher mineral trapping capacity, mainly because of reservoir pressure in addition to the presence of glauconite as an iron source for siderite formation.

These results reveal that mineral trapping in the Nugget formation is not significant but that total chemical trapping might be much more than that of hysteresis trapping. Therefore, the contribution and importance of chemical trapping in CO2 sequestration should be taken into account for assessment of CO2 sequestration.
Case History Using ESP's to De-Water Horizontal Wells
Authors: Bassett Lonnie
Published: February 2011

Over the past 20 years, the evolution of de-watering unconventional gas wells has gone from simple vertical to more complex horizontal wells. Each has had it learning curve and each has had its own challenges to overcome. No application has been more challenging that getting results for de-watering horizontal wells.

This paper will focus on real case histories of this learning curve and discussion on what has worked best and what has not worked at all. We will discuss methodologies that were used to overcome specific challenges and although it is recognized that each application is different, these two case histories will show the commonalities that can be seen in all horizontal unconventional gas wells. No claim can be made that all wells are alike and this paper will not make this claim. However, these two examples will show that there are similarities that can be universally addressed and if nothing else it gives a better starting point without having to reinvent the wheel.

The paper will cover specific wells, each with a different completion technique and the challenges faced by each. This paper will cover new information not yet submitted under any review and showcase methods used to solve these challenges.

Specific examples will be shown how the initial attempts to draw the well down and subsequent gas production was hampered by old techniques and what was developed that let to a fourfold increase in gas production by being able to de-water below the bend.

1. Electric Submersible Pumps (ESP's) best practices for a horizontal well: A horizontal well is a place an ESP's flexibility can really shine. This paper will identify the key areas that drastically improve the chances of success. The paper will identify the operational differences and the different options in running in a horizontal well compared to a vertical well. It will cover the preplanning required to avoid negative operational issues including gas locking, solids intrusion and optimized draw down.

This paper will concentrate on horizontal wells and highlight techniques that will increase the effectiveness of utilizing ESP equipment for dewatering.
Development of a Steam-Additive Technology to Enhance Thermal Recovery of Heavy Oil
Authors: Srivastava P. , Sadetsky V. , Debord J. , Stefan B. , Orr B.
Published: February 2011

Steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS) and steam floods are widely employed in the industry to extract heavy oil. These techniques use steam to lower the viscosity of bitumen, which translates into improved production. Sustainability of the enhanced production is primarily dependent on the ability to generate large volumes of steam. Steam generation consumes large amounts of natural gas and leads to higher CO2 emissions, which impacts profitability of the SAGD operation and the environment in a negative way. This problem, a technological void, calls for a solution with higher oil production for the same level of steam consumption, and thus higher profit margins. This paper reports how adding a chemical to the steam enhances production rates and recovery factor from the Alberta Oil Sands. The steam pumped into the reservoir serves as a carrier for the chemical additive. The additive allows condensed water to retrieve more bitumen by allowing higher mobilization of the bitumen deposits. Laboratory-scale simulations were conducted using a gravity-driven displacement process. Steam at 200°C and 2000 kPa was passed over an unconsolidated oil sands core sample. The results of the experiment were highly encouraging. An additive dosage rate of 1000 ppm resulted in a 13.5% increase in heavy oil recovery compared to the baseline (no additive, pure steam). This enhanced production at a low dosage rate of 1000 ppm prevents the need for any economically driven recovery of the chemical additive.
Wellbore Strengthening: The Less-Studied Properties of Lost-Circulation Materials
Authors: Kumar Arunesh , Savari Sharath , Whitfill Donald L. , Jamison Dale E.
Published: February 2011

Lost circulation is one of the major issues that lead to unwanted non-productive time (NPT) while drilling with a narrow mud weight window and it requires engineered solutions to address the problem. In several instances in the past, wellbore strengthening was achieved by treating the drilling fluid with lost circulation material (LCM), utilizing Stress Caging or Wellbore Strengthening theory. Small fractures were propped and sealed with a proper size distribution of particles that isolates the fracture tip from fluid pressure and controls the fracture propagation, effectively increasing the near wellbore hoop stress.

Laboratory data and field experience indicate limited success may occur if a single material such as sized calcium carbonate is used alone for wellbore strengthening. This is possibly due to size reduction that may occur while drilling or due to fracture closure stresses (FCS) acting on the particles. However, using calcium carbonate in conjunction with resilient graphitic carbon (RGC) material has shown to be effective in increasing the formation integrity.

The effect of mechanical properties of LCMs on wellbore strengthening has been investigated using compression/crush tests at different confining pressures simulating a wide range of FCS. Crush test demonstrated compaction and significant crushing of the ground marble and ground nut shells at high confining pressure (~ 5000 Psi). Considerable improvement in the crushing resistance and resiliency of these materials was observed with small additions of RGC. Knowledge of deformation and failure behavior of different LCM materials may result in better design. In this paper recommendations are made on different combinations of LCM that may be used more effectively to provide wellbore strengthening.
The Late Miocene Coalbed Methane System in the South Sumatra Basin of Indonesia
Authors: Mazumder Saikat , Sosrowidjojo Imam B. , Ficarra Alessandro
Published: February 2011

The purpose of this paper is to provide a view on the South Sumatra basin CBM development potential. The basin ranks as one of Indonesia's most prospective coalbed methane (CBM) basins, but well testing is still in the earliest stages. In S. Sumatra basin there are three distinct identifiable sub-basin evolution periods. First, a period of horst-graben development controlled by major localized extensional faults that initiated the basin architecture. This episode was followed by rapid to moderate sedimentation controlled by normal faults resulting in deposition of Oligocene Talang Akar alluvial, fluvial and deltaic deposits. Secondly, a period of decreased fault activity along with regional subsidence coinciding with the deposition of the post-rifting Miocene Air Benekat and Muara Enim Formations. The third period is marked by regional uplift resulting in wide spread basin inversion over the entire region. Coal seams in the Muara Enim Formation are thickest and most numerous in the SW half of the South Sumatra basin representing key target for CBM development. This is the axial region of the basin where the subsidence has been most pronounced and the formation is thickest. While the coals are quite thick and laterally extensive in the broad synclines, most of the Miocene Muara Enim Formation has been eroded out along the anticlines. The Lematang Depression and the Central Palembang sub-basin are considered the most prospective CBM areas on the basis of coal thickness, depth, and gas kicks on mud logs. The Muara Enim formation comprises more than 3500 ft of paralic sandstones and mudstones, with thick intercalated coal seams. Typically some 10 to 15 individual coal seams are present.

The coals are of sub-bituminous rank and characterized by low vitrinite (huminite) reflectance (VRr = 0.35 – 0.46%). These low rank coals are dominated by huminite (34.6 – 94.6 vol. %). Less abundant are liptinite (4.0 – 22.5 vol. %) and inertinite (0.2 – 43.9 vol. %). Minerals are found only in small amounts (0 – 5 vol. %); mostly as iron sulfide. Kaolinite occurs as cleat fillings at some places. The coals are characterized by high moisture content (4 – 21 %) and volatile matter content (> 40 wt.%, daf), and less than 80 wt. % (daf) carbon cotent.

CO2 and CH4 sorption isotherms on six different coal samples were carried out at reservoir temperature. Given the uncertainty around the gas content measurements, the coals tend to suffer from some serious under saturation. The sorption capacities of the coals tend to decrease with increasing depth. This behavior can either be related to the increasing moisture content of the coal with depth or with the significant variation of the vitrinite content of the deeper seams. The high CO2 adsorption capacity and the low rank tend to make these coals ideal targets for CO2 sequestration.
Advanced Sand-Face Completion Design and Application in Gas and Gas-Condensate Fields
Authors: Al-Khelaiwi F. T. , Davies D. R.
Published: February 2011

Sand-face completion technology for gas wells has evolved to overcome problems associated with sand and water production. Frac-packs, gravel packs, screens and oriented or selectively perforated completions have all been applied to gas wells to maintain wellbore integrity and control expected, late-life production challenges. However, none of these completion designs are capable of managing variable productivity, pressure or sanding tendency when producing multiple reservoir layers into a single wellbore. The result is premature water and (often) sand production. Intelligent completions employing Interval Control Valves (ICVs) can successfully manage these problems. However, not only are there limitations on the number of zones that can be separately controlled, but the hardware is also susceptible to the increased erosion potential of the high flow velocities associated with gas production.

Inflow Control Devices (ICDs) are an alternative Advanced Well Completion (AWC) technology. An ICD employs a passive flow restriction mounted on each joint of tubing or sand-control screen. The Autonomous Inflow Control Device (AICD) adds an "Active" water shut-off element to the flow equalisation provided by the standard ICD. An (A)ICD completion consists of multiple joints of (A)ICD equipped tubing separated into the required number of zones by Annular Flow Isolation (AFI). Such completions have the ability to equalise the gas inflow from many more layers (or even separate reservoirs) than is possible with an ICV or separated conventional completion.

This paper will present a critical evaluation of the ICD and AICD technologies together with a novel design methodology for their application to gas fields. This will be complemented by two case studies based on real data from both a gas and a gas- condensate field. These studies will be used to illustrate the application of the design workflow along with the potential advantages and added value derived by installing (A)ICD completions.

This design methodology and the field studies provide the basis for an extension of the (A)ICD's application envelope.
Henry Subsea Development - Challenges and Solutions
Authors: Henzell Stephen , Glucina Andrew
Published: February 2011

The Henry and Netherby gas fields are located in Victorian waters in South East Australia. They have been developed by extending the Casino production system which comprises two subsea wells in the Casino field producing by offshore and onshore pipelines to an onshore gas plant. The entire Henry and Netherby development is subsea, connecting to the Casino pipeline in 70 metres of water.

During the Casino design, provisions were made for future extension of the production system. This paper discusses the provisions made and their effectiveness during the expansion project. The paper also discusses some of the challenges encountered by the project team and how they were overcome.

Specific project challenges included dewatering the pipeline extension without direct access to a production facility, pressurization of the pipeline extension and safe removal of nitrogen from the pipeline extension. The paper also covers the hydrate management of the extension wells, pipeline hydraulics and commercial issues that affected the project development.
Living in Harmony—Gas Production and the Attwater's Prairie Chicken
Authors: Haut Richard C. , Bergan James F. , Judy Jared , Price Liz
Published: February 2011

Over a century ago, one million Attwater's prairie chickens graced the coastal grasslands of Texas and Louisiana. Today, less than 1% of their native habitat remains and in 2009, it was estimated that only 90 remained in the wild at three different locations. The remaining nearly 260 Attwater's prairie chickens are in captive rearing facilities throughout Texas. One of the last remaining locations where the Attwater's prairie chicken is found in the wild is the Texas City Prairie Preserve that was set aside near Texas City and is owned by The Nature Conservancy (TNC). The Conservancy has leased oil and gas production on the Preserve and works to balance production with the conservation and recovery of the Attwater's prairie chicken.

The Houston Advanced Research Center (HARC) is leading an industry consortium effort, the Environmentally Friendly Drilling Systems (EFD) Program, to investigate the development of cost-effective, low impact drilling and production systems and to reduce the environmental tradeoffs associated with operations. The work originated in 2005 when co-funding was obtained by the U.S. Department of Energy and industry. Additional funding for the effort was obtained through the Research Partnership to Secure Energy for America (RPSEA).

The paper documents how HARC and TNC partnered to investigate if and how noise from production operations affects the Attwater's prairie chicken. An electrical submersible pump (ESP), powered by a 500 kW diesel electric generator, was installed in a gas well to increase production. Attwater's prairie chicken locations and movements were monitored prior to, during the workover, and following the installation of the pump (operation of the diesel generator). Noise measurements for the operation of the diesel generator were recorded. Locations of Attwater's prairie chickens were compared to the before, during and after time periods relative to the ESP installation.
History Matching With Learned Sparse Dictionaries
Authors: Khaninezhad Mohammad-Reza M. , Jafarpour Behnam , Li Lianlin
Published: February 2011

History-matching of heterogeneous hydrocarbon reservoirs is carried out to construct predictive reservoir models that: i) provide accurate predictions of fluid displacement and future reservoir production behavior; ii) honor all existing measurements; and iii) preserve prior knowledge about geological continuity. Estimating individual gridblock heterogeneous reservoir properties from limited static data and spatially averaged dynamic production measurements inherently leads to an ill-posed inverse problem that can have several non-unique solutions. Many geologic formations consist of a finite number of continuous rock types (facies) with distinct hydraulic properties and spatial distributions that constrain the global fluid displacement patterns. In such cases, a feature-based history-matching technique (instead of gridblock property estimation) is more appropriate. In this paper, we present a novel and geologically motivated feature estimation method for solving history-matching problems more effectively and consistently. Using an ensemble of prior geologic models, we apply a sparse learning algorithm to generate a large number of geologically relevant model elements (similar to "words in a dictionary"). The sparsity of the constructed dictionary implies that only a small set of dictionary elements (i.e., "words") are needed to construct, according to the information in the static and dynamic production measurements (i.e., "intended meaning"), a history-matched model (i.e., "a sentence"). The sparse learning method used to generate the geologic dictionary is a recently developed machine-learning algorithm known as K-SVD. The K-SVD algorithm builds a "sparse dictionary", with flexible dimensionality, from a prior model library. An important property of the geologically learned dictionary is that only a small set of its elements is needed to reconstruct the history-matched model (i.e., solution sparsity). To achieve solution sparsity, we implement an iteratively reweighted (sparsity) regularized least-squares algorithm to selectively combine and weigh a small subset of relevant model elements from the learned dictionary that explains the observed data. We use several examples from fluvial formations with channel features and Tarbert-like formations resembling prograding near shore depositional environments, to illustrate the validity and effectiveness of the proposed history matching approach.
Surveillance Modeling and Operational Controls Ensure Integrity of Alaska's Grind and Inject Operations II
Authors: Zaki Karim S. , Zhai Zongyu , Abou-Sayed Ahmed S. , Marinello Stephen , Bill Michael L. , Engel Harold R.
Published: February 2011

Alaska's Grind and Inject (GNI) operations represent the longest and largest semi-continuous solids waste slurry injection project worldwide. More significant in the current climate of corporate responsibility is that modeling updates and assurance processes allow procedural updates to maintain efficiency and environmental integrity. The modeling program provides data for injection performance analysis and history matching that leads to better understanding of subsurface dynamics. Operational success is evidenced by unblemished capacity to accept large waste volumes with significant ultimate well disposal potential.

This paper addresses injection assurance and waste containment throughout project life. The periodic history match of created subsurface features is a major component of this process. Fracture simulation was carried out to match the subsurface response to slurry batch injection through 8 years of injection. The geomechanical modeling necessary to provide the framework on which the simulation works is described. Stress evolution and thermal effects during batch injection is also illustrated for the GNI environments. The disposal domain development has been inferred from the simulation.

The provision of designs, solutions and predictions based on the simulation sensitivity studies is described and the impact of field activities is highlighted. Designs, solutions and predictions are given based on the numerical results and sensitivity study verified by past field observations. The verification and updating of the model developed for the GNI operation is provided by the history matching of wellhead pressures through eight years of injection.
Effect of Permeability Impairment by Suspended Particles on Invasion of Drilling Fluids
Authors: Tran Tung V. , Civan Faruk , Robb Ian
Published: February 2011

This study experimentally and numerically investigates formation damage induced by suspended particles in the drilling fluid and its effect on limiting their near-wellbore invasion. The study applies the NMR and X-Ray digital radiography tprovide valuable insights into damage mechanisms along the formation and depth of invasion. Formation damage caused by drilling fluids is one of the key factors for economic success in oil and gas field developments. The measured permeability reduction obtained from laboratory test by injecting particulate drilling fluid in a representative core sample is used to determine empirical parameters used to model the particle migration and deposition in porous media by means of a robust simulation of the relevant processes. The study provides a concept to develop the ability to evaluate drilling fluids in term of their formation damage potential.
Effects of CO2 Density and Solubility on Storage Behavior in Saline Aquifers
Authors: Takasawa T. , Kawamura T. , Arihara N.
Published: February 2011

CO2 sequestration in deep saline aquifers is an essential and quick-remedial measure to reduce CO2 emissions to atmosphere. At conditions of 800 to 4000 meters deep aquifers, CO2 is supercritical and a liquid-like fluid of which density and solubility into water are strong functions of pressure and temperature. In geological sequestration of CO2, behavior of the injected CO2 undergoes multi-phase flow, dissolution into the aqueous phase, and reaction with rock. In aquifers of the closed boundary or open boundary with weak regional groundwater flow, densities of CO2 in its own phase and CO2-dissolved water dominantly influence the extent of horizontal and vertical CO2 migration. In this study, we investigated effects of CO2 and aqueous-phase densities on the migration extent for a long time scale after injection.

In order to simulate advection, dissolution, and precipitation processes, we first developed a streamline-based model assuming incompressible and immiscible two-phase flow of CO2 and water. Procedures of the common streamline method were followed. Along streamlines, 1-dimensional flow equations were solved for CO2 in its own phase and CO2 concentration in aqueous phase, where reaction of dissolved CO2 is accounted for in the latter equation. CO2 flow due to gravity was calculated on the underlying grid, and so were permeability changes.

After validating the model, we performed simulations of CO2 sequestration in 3-dimensional homogeneous and heterogeneous aquifers. CO2 migration at a long timescale depends on the aquifer pressure and temperature that directly influences density, viscosity, and solubility of CO2 phase. The gravity segregation is controlled equally by aquifer pressure and temperature, and by vertical permeability, while the advective migration is less affected by the pressure and temperature, but more by heterogeneity. As precipitation, that is the ultimate form of sequestration, is directly related to migration extents of CO2 and aqueous phases, CO2 injection schemes need to be appropriately designed in accordance with the aquifer pressure, temperature, and heterogeneity.
Solving Future Challenges: Understanding Factors That Influence Innovation
Authors: Singh Amardeep
Published: February 2011

Innovation is the key ingredient to the success of any technology-based company independent of its size, market position or global presence. There are numerous worldwide examples that document that a company's success is directly linked to its ability to innovate and solve complex drilling and completion challenges in increasingly difficult environments. Generally, most technology providers strive to be innovative, but many struggle to accomplish the goal. Questions arise; why cannot all companies be innovative; why are certain companies more innovative than others; why are some companies innovative over a certain period of time and then lose their ability to sustain it?

An initiative was recently launched to answer these questions. The process involved soliciting input from grass root employees about their perception of company innovations over the past 20 years. The main objective was to identify the underlying themes influencing and driving the innovation process. Finally, we wanted to determine what type of environment or culture is most likely to encourage and motivate employees to create innovative new technologies/ideas.

This paper will outline key factors that correlate to a company's ability to create innovations from within. The conclusions are derived from extensive internal studies, but they are applicable to all technology-driven companies across a broad spectrum of industries. We will include a list of action items designed to change a company's culture to encourage innovation. These recommendations will also help companies sustain and predict innovation cycles.

When the next upturn in drilling activity begins, the industry must be prepared to respond with new and updated technologies/services to meet the next generation of drilling and completion challenges. By first understanding, then fostering a culture of innovation, the service industry will be properly positioned to efficiently accomplish future operator driven goals and objectives.
Operator/Service Company Research Collaboration Leads to Reduced Downhole Vibration Levels and Improved Drilling Performance
Authors: Chesher Steven W. , Williamson Mark E. , Dougherty Bill B. , Spencer Reed W. , Schmitz Kurtis , Tyagi Sarvesh K.
Published: February 2011

The Cana Woodford shale play is emerging as an active natural gas field in Oklahoma, USA with over 100 wells already drilled and many more in the pipeline. However, the key to success, especially with the current depressed pricing of natural gas, is continued injection of technology leading to reduced drilling costs. The most common well profile drilled in Canadian County and Blaine County, Oklahoma consists of a vertical section followed by a curve section and a long horizontal section through the Cana Woodford shale. Downhole vibrations were identified as major drilling performance limiters in the 8 ¾ in. and 12 ¼ in. vertical hole sections in these applications. The operator and the service company started a collaborative project to measure, understand, and reduce vibrations of the bit and BHA in order to improve drilling performance. The project adopted a holistic approach that included the use of analytical drilling models, drilling lab facilities, an experimental test rig and field testing to study how bits, BHA's and operating parameters impact downhole vibrations. All testing in the drilling lab, at the experimental test rig, and in the field incorporated in-bit vibration sensors.

In this paper, the authors will illustrate how a collaborative effort between an operator and a service company can leverage the collective knowledge and experience of both organizations for scientific investigation into the most important drilling dysfunction -downhole vibration. Based on testing in the lab, the experimental rig and the field, changes in the BHA and drive mechanism were implemented. These changes led to significant reductions in vibration levels, improved performance and better bit dull conditions. It is anticipated that as the collaboration moves forward, reductions in downhole vibration will translate into continued improvement in ROP, longer tool life, and significant cost savings for the operator.
Streamlined Production Workflows and Integrated Data Management: A Leap Forward in Managing CSG Assets
Authors: Biniwale Shripad , Trivedi Rajesh , Zangl Georg , White Chris , Delaney Scott , Blair James
Published: February 2011

A case study of the Spring Gully coal seam gas (CSG) field illustrates how an integrated production data management and analysis system has consolidated scattered data sources into a unified repository to provide easy access for reporting and analysis. Automated surveillance workflows with notification and alarm capabilities have simplified production performance tracking and enabled proactive decision making. Current analysis techniques and expert knowledge have been captured in predefined templates and workflows to identify trend violations, flagging the issues and optimizing production.

The new system has provided a foundation layer for managing the production and deliverability of thousands of wells now and in the future, helping to translate data into information. Enabling timely decision making through the use of accurate, validated data and automated workflows has helped engineers focus on problem solving and analysis. The streamlined process will continue to help the operator's CSG teams improve the efficiency and productivity of all their assets.