bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation and Application of Real-Time Image and Caliper Data as Part of a Wellbore Stability Monitoring Provision
Authors: Greenwood J. , Bowler P. , Sarmiento J. F. , Willson S. , Edwards S.
Published: December 2007

Wellbore instability remains a leading cause of drilling nonproductive time (NPT), despite a considerable amount of work on the subject in recent years. For the most part this is not caused by a lack of understanding of the mechanics of wellbore instability. Rather, it is caused by the limitations of pre-drill subsurface predictions. In other words, it is the drilling surprises often encountered in reality, but not predicted prior to drilling, that give rise to wellbore instability problems. These surprises include formation tops and pressures occurring at different depths than predicted and the presence of unexpected faults or other fractured or fissile zones.

Typically, while drilling today, downhole data useful for understanding wellbore stability is scarce. Much of what we have to go on is indirect measurements; torque and drag observations, cavings, and annular pressure measurements. In order to unambiguously understand and therefore mitigate the wellbore instability problem, more information is needed.

Real-time wellbore stability modeling goes some way toward this goal. However, the missing piece in almost all cases is some direct observation of the state of the hole to determine where and how the wellbore is failing. LWD calipers and/or wellbore images can provide such information, and the option of transmitting the information to surface while drilling is now often possible.

This paper will present the results of a project conducted to evaluate the available real-time images, memory density images, and acoustic caliper information and their incorporation into an existing wellbore stability monitoring service.
Mitigating Application-Specific Challenges Through a Total System Approach
Authors: Stavland M. , Wolter H. , Evans J. G.
Published: December 2007

Economical demands within the oil and gas industry are the driving force to exact significant advances in Drilling and Formation Evaluation Technology. This has been exemplified by the application of new technology to address the complex challenges of the Troll Field Reservoir in the Norwegian North Sea.

Exploiting the Troll reservoir requires horizontal geosteering through relatively unconsolidated sandstones with localized zones of hard calcite-cementation. Optimum well placement is of the utmost importance and demands reduced tolerance for any inaccuracy within the thin oil reservoir column throughout the progressively increasing drained hole section. Consequent to the advancement in drilling technology, the horizontal reach has been extended from some 500 meters to more than 5000 meters in a single reservoir section including horizontal turns of up to 360°.

In 2001 an innovative service was introduced to the Troll field, being founded on a new multi-sensor data acquisition and processing Measurement-While-Drilling (MWD) tool. The downhole tool contains various dynamics and mechanical sensors, and a high-speed data processing system to continuously provide an accurate picture of the downhole conditions and the energy transfer train. The service was deployed to optimize the mechanical efficiency of the drilling process by facilitating the immediate response to differing situations encountered while drilling complex heterogeneous formations. This real-time service, but also the intrinsic detailed studies on BHA and bit design with ensuing in-depth knowledge capture have lead to a comprehensive understanding of the Troll drilling challenges and thereby facilitated the design and utilization of application specific bottom hole assemblies with associated relevant drilling procedures and practices.

This paper will discuss how this technology is used and how this total drilling system deployment concept has been applied to successfully surmount the specific challenges of the Troll Field.
Integrating Emerging Drilling Methods From Floating Drilling Rigs—Enabling Drilling Solutions for the Future
Authors: Kozicz J. R. , Juran T. L. , de Boer L.
Published: December 2007

Drilling offshore oil and gas wells is more challenging than ever. Drilling problems resulting from narrow margins between collapse and fracture pressures, pore pressure uncertainty, high pressure, high temperature, and wellbore instability have resulted in significant additional cost because of the time required to rectify these drilling problems.

These problems can occur in both shallow and deepwater areas and are similar to drilling problems encountered in many land drilling areas. These problems have multiple origins related to: geo-mechanics, rock and fluid chemistry, temperature, local and regional tectonic stresses, abnormal or sub-normal pressures etc. Many methods have been developed or proposed to address these wellbore stability problems. These included: addition of wellbore strengthening agents, wellbore temperature management, expandable casing, and wellbore pressure management among others. This paper considers those methods related to wellbore pressure problems, and the tools and techniques that have been developed to overcome these.

The paper discusses the challenges and possible solutions required to cost effectively integrate these Emerging Drilling Methods with existing offshore drilling equipment to facilitate deployment of these drilling methods from floating drilling rigs.
Improved Deepwater Cementing Practices Help Reduce Nonproductive Time
Authors: Vargo R. F. , Heathman J. F. , Kellingray D. S. , Ward M. D. , Lummus J. M.
Published: December 2007

Over the course of a 4-year period, during which approximately 42 wells were constructed by this operator, processes were developed to improve cement slurry design and reduce nonproductive time (NPT) during cementing operations on deepwater wells.

Cementing best practices have been followed for many years; however, not all of these practices are applicable to deepwater operations, especially for the riserless sections. Results of developing (1) slurry design practices, (2) temperature prediction and mud removal modeling, and (3) the use of SSR® subsurface release plugs will be reviewed.

The choice of cement blend used can have a profound impact on cost, not only in terms of failure in the event of the wrong design, but also in terms of supply logistics. As deepwater operations move farther away from shore bases, the need for a systems approach to cover all cement design needs from conductor to plugging should be considered. The challenges across this breadth of application range from dealing with shallow water flow potentials to relatively high temperature and pressure. Both conventional and foamed cement slurries can be successfully used in this endeavor when properly designed and placed. Placement design should include a thorough understanding of the static gel development behavior of the drilling fluid.

Although it is generally accepted that conventional circulating temperature estimates are not appropriate for use in deep water, the use of alternatives is not always practiced. Over the course of this project, this operator realized better cement slurry performance and lower slurry costs following the correct use of wellbore thermal simulators. Attention to detail in applying the correct data to computer simulations resulted in lower slurry costs while at the same time achieved improved performance as measured by improved casing shoe integrity.

Real-time monitoring and detailed pressure analysis were used to manage cementing operations and the correct application of SSR plugs. Feedback of these processes from operators and service tool personnel has resulted in improved job performance as measured through reduced NPT and well construction costs. These new processes have resulted in a 100% success rate as compared to the previous 74% success rate.
Effective High-Density Wellbore Cleaning Fluids: Brine-Based and Solids-Free
Authors: Javora P. H. , Baccigalopi G. , Sanford J. , Cordeddu C. , Qu Q. , Poole G. , Franklin B.
Published: December 2007

Displacing drilling mud with clear solids-free completion brine is a critical step during well completion. As we move into deeper waters and drill to deeper depths (greater than 25,000 feet MD), conventional methods and cleaning fluids become a limiting factor in this phase of the operation. Conventional cleaning fluids use fresh water or seawater treated with surfactants to remove wellbore solids and water wet tubulars. Using low-density cleaning fluids creates a negative differential pressure between the working kill weight fluid and the formation, casing and cement liners. In many situations, the negative differential pressure cannot be tolerated and the risk of failure at the liner top, etc. is increased, especially if the wellbore has not been pressure integrity tested. Additionally, with increasing rig / spread costs, high pump rates are necessary to decrease the time it takes to perform these operations. The pump rate is indirectly proportional to the pump pressures required. Weighted spacers decrease the overall pressure differential, which allows for higher pumping rates.

In order to overcome the density limitation of these cleaning fluids, conventional techniques such as additional hydraulic horsepower, backpressure schedules, the addition of solids to lighter cleaning fluids (water, seawater), or balancing the weight of the low-density cleaning fluid with a matching higher-density fluid is utilized. However, each of these "fixes" has inherent limitations and is accompanied with reduced cleanup efficiency. Furthermore, conventional surfactants are not active or effective in high-density brines. New brine-compatible surfactant chemistry and the corresponding balanced-displacement engineering design were developed to overcome limitation of conventional displacement technology.

This paper describes the field applications of new brine-based high-density solids-free cleaning fluids in balanced-displacements in deepwater and offshore shelf wells. The new high-density fluids were based on, new surfactant technology developed to ensure effective wellbore cleaning, wellbore design parameters, and displacement modeling. In addition, weighted spacers aid in reducing high pump pressures and wellbore pressure differentials. In one case history, maximum pumping pressure of more than 9,000 psi was expected for conventional water based displacement, but was reduced to a little over 3,000 psi with the new design. High-Density cleaning fluids, with densities up to and greater than 17.5 ppg, have been formulated and utilized successfully without compromising cleanup efficiency and significantly reducing differential pressures. Results from laboratory development and field applications are presented.
Visualization of BHA Dynamics Improves Understanding of Downhole Drilling Conditions, Speeds Up Learning Curve
Authors: Jogi P. , Macpherson J. , Neubert M. , Reckmann H. , Heisig G.
Published: December 2007

The drilling industry demographics predict a significant loss of expertise in the upcoming years as a high percentage of drilling personnel will reach retirement age. At the same time, drilling activity is predicted to grow driven by high oil prices based on strong demand. As rig rates go up, failures in downhole drilling equipment as a result of downhole conditions will become even more costly, resulting in an increased demand for experienced personnel. There is, therefore, a widening experience gap that needs to be addressed as fast as possible.

Over the past few years, the service industry has developed sophisticated downhole1,2,3 and surface data acquisition systems that can record critical drilling parameters at a level of detail and accuracy not available before. In particular, on the downhole side it is now possible to store significantly more data at a fraction of the cost compared to earlier years. However, while more data are now available, the analysis is still done in the traditional manner via logs or special signal processing systems requiring a high level of expertise. As a result, large amount of data are acquired today, but only few experts are available to do a detailed analysis so that a lot of the data are never looked at.

Visualization tools can be a solution to this dilemma. They can provide a much faster learning curve about downhole conditions while drilling. Computer animations facilitate re-playing data recorded downhole at a high rate, displaying the motion of a downhole tool inside the borehole. Combining downhole data with BHA modeling software allows the user to review the mechanical loading of the BHA in the section just drilled, and to focus attention on special events or sections as necessary.

The paper reviews dynamics data sources and formats available today and present several example displays and animations that show how visualization can aid the process of analyzing large amount of data. In addition to the visualization of recorded data, the paper also presents real-time visualization-while-drilling that is intended to enhance the drilling crew's understanding of the downhole conditions. The paper finishes with a short discussion of the benefits of using animations and visualization tools in training programs and education seminars.
Real-Time Downhole Torsional Vibration Monitor for Improving Tool Performance and Bit Design
Authors: Chen D. C.-K. , Comeaux B. , Gillespie G. , Irvine G. , Wiecek B.
Published: December 2007

A new downhole torsional vibration sensor built into a rotary steerable system has provided a new monitoring system for improving drilling efficiency and avoiding downhole failures related to torsional vibration. The strength of the new sensor is that it measures rotational changes right at the bit as compared to the usual 50-100 feet behind the bit with conventional MWD/LWD sensors. In addition, the sensor is always at the same location regardless of BHA configuration, which provides a higher level of consistency in torsional vibration measurement. The ability to evaluate bit performance objectively has consequently resulted in better bit design and rotary steerable tool performance.

The new torsional efficiency monitor has been used in areas where torsional vibration was recognized as a problem. This paper will discuss the application of the real-time downhole monitor and the results from detailed analysis of the data from the initial field runs in these harsh environments. The ability to immediately detect the occurrence of torsional vibration and to take corrective action before failures occur has significantly improved the ability of the rotary steerable system to survive harsh conditions.
Understanding the Pressure Gradients Improves Production From Oil/Water Transition Carbonate Zones
Authors: Carnegie A. J. G.
Published: December 2007

Worldwide, carbonate oil-water transition zones contain vast amounts of producible oil. Yet, traditional approaches to open-hole formation evaluation often fail to predict how much oil should flow from them, or even the location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading mud filtrate and formation oil, to result in the following unusual yet often observed behavior: 1) negative pressure gradients, 2) water-like gradients significantly above the free water level, 3) significant shifts in the measured pressure potentials between the lower and upper part of the transition zone, 4) gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considered. It is shown how it is usually possible to produce oil from a zone which has a water-like pressure gradient and low formation resistivity. The theory is supported by detailed analysis of examples from flow simulations, which recreate the well known field cases referred to above. Guidelines are presented on how to interpret traditional open hole pressure measurements in a carbonate oil-water transition zone to determine the free water level and the locations where oil should flow, and on how to improve on these interpretations by performing more advanced formation testing procedures, some of which are based upon new technology.
High-Quality Electrical Borehole Images While Drilling: Increased Confidence in Well Positioning and Drilling-Hazard Mitigation From Real-Time Data
Authors: Morris S. , Lofts J. , Lindsay G. , Fulda C. , Dahl J.
Published: December 2007

Recent developments in technology have lead to the ability to acquire and transmit high resolution electrical borehole images while-drilling. The advantage of imaging while drilling is to acquire data with minimal rugosity of the borehole wall and before appreciable invasion of the drilling fluid in order to obtain the best possible quality images. High quality, real-time images and the resulting ability to proactively steer the drill bit provide benefits to both the driller and geologist through the ability to make real-time decisions on optimum well placement. Further implications for the driller are reduction in NPT through drilling hazard mitigation and maintaining borehole stability because of the immediate identification of breakout. For the geologist, the real-time interpretation of structural and sedimentary information from electrical images can be used to steer the drill bit in order to: stay inside a desired sedimentary package based on the rapid interpretation of sedimentological criteria (e.g. sedimentary steering by using predictive models of sandbody geometry and internal architecture),give fore-warning of approaching features in the proposed drill path (e.g. fracture intensity increasing towards a fault zone), andavoid or mitigate adverse features that may have a negative impact on production (e.g. avoiding reservoir roof rocks by steering away in advance).

Field tests have shown the ability to transmit to surface real-time compressed images that can be optimized for deriving structural information whilst higher resolution images can be used for sedimentary analysis. This paper shows how these developments can be used to increase confidence in well placement, at the same time as avoiding drilling hazards.
Deployed Smart Technologies Enablers for Improving Well Performance in Tight Reservoirs—Case: Shaybah Field, Saudi Arabia
Authors: Salamy S. P. , Al-Mubarak H. K. , Hembling D. E. , Al-Ghamdi M. S.
Published: December 2007

Intelligent wells are becoming the buzz word in the oil and gas industry. Today the development and deployment of smart technologies are important drivers for improving well productivity and delaying early water or gas breakthrough in tight and challenging reservoirs.

Shaybah field, a low permeability reservoir overlain by a huge gas cap was initially developed in 1996 with one-km single lateral horizontal wells to effectively drain the hydrocarbon while reducing gas coning. A step development approach by increasing the reservoir contact to improve well productivity and performance was the basis for Maximum Reservoir Contact (MRC)1 concept. Maximizing reservoir contact through MRC wells was one of the measures taken in early 2002 to reduce gas coning and improve recovery. Results to date from 37 MRC wells have indicated a four fold increase in well productivities and a three fold decrease in unit development cost when compared to the one-km single lateral wells.

In addition, several advanced completion technologies such as downhole flow control systems (smart completions), expandable liners, and production equalizers were deployed in Shaybah Field. These technologies have shown major improvements to well performance and recovery. Smart controls assisted in optimizing production from each lateral in a multi-lateral setting in the event of premature gas or water coning. In addition, downhole smart completions improved well productivity in multi-lateral wells through an improved well cleanup process. Production equalizers when deployed in high GOR wells reduced gas coning by 50% and improved well productivity. To date, over ten expandable liners have been deployed as enablers to a workover strategy to convert single lateral wells to Multi-lateral/MRC wells thereby providing the platform for installation of downhole flow control systems. Shaybah Field holds several world records in the area of technology implementation; one of which is for the first MRC window to exit from 5-1/2" expandable allowing the placement of 2-7/8" ICV for inflow control. This paper will highlight how smart technologies have positively impacted field performance.
Generalized Analytical Solution for Reservoir Problems With Multiple Wells and Boundary Conditions
Authors: Busswell G. , Banerjee R. , Thambynayagam R. K. M. , Spath J.
Published: December 2007

We present a set of new analytical solutions to the single layer reservoir problem, both in real time and Laplace space. The solutions are derived assuming a cuboid shaped reservoir using a method of integral transforms. The method can be applied to calculate the pressure as a function of position and time when using any continuous function to describe the production rate of a point source. Successive integration of the point source solution can be performed to calculate the average bottom hole pressure of a well.

These equations are applicable to partially penetrating vertical, horizontal and fractured wells and take into account superposition effects in multi-well and multi-rate scenarios. Notably, regarding fractured wells, we are able to accurately model the case of a finite conductivity fracture with non-Darcy flow as well as those of infinite conductivity. The generality of our method allows any continuous function of position and time to be used to treat either pressures or fluid fluxes on the boundaries.

Also, using solutions in Laplace space we are able to model naturally fractured reservoirs, wellbore storage, non-Darcy D-factors as well as constant well pressure production, also all within a full field multi-well scenario. Our method, therefore, provides a powerful alternative to simulation in terms of reservoir modeling.

We present a comparison of our solutions with that generated using a commercial finite difference simulator for a variety of problems in terms of accuracy and speed. We find amazing accuracy with massive gains (factors>300) in CPU times for fracture problems in particular.
Supercritical CO2 and H2S—Brine Drainage and Imbibition Relative Permeability Relationships for Intergranular Sandstone and Carbonate Formations
Authors: Bennion D. B. , Bachu S.
Published: December 2007

Sequestration of CO2 and H2S (acid gas) in deep underground formations is a means for reducing atmospheric emissions of acid gas produced from sour gas reservoirs that has been practiced for 15 years in North America and that is currently being considered in other regions such as the Middle East and central Asia. Furthermore, acid-gas injection operations constitute a commercial-scale commercial analogue to CO2 injection in geological media as a climate change mitigation measure. Deep saline aquifers provide a very large capacity for the sequestration of acid and greenhouse gases, being ubiquitous in all sedimentary basins around the world. Proper understanding of the relative permeability character of such systems is essential in ascertaining gas injectivity and migration, and in assessing the suitability, containment and safety of prospective injection sites.

Pure CO2 and H2S represent the compositional end-members of acid and greenhouse gases, thus the interest in measuring their displacement properties. This paper presents the detailed experimental equipment and protocols, and the results of a series of relative permeability tests conducted at full reservoir conditions using supercritical pure CO2 and H2S on samples of intercrystaline sandstone and carbonate rocks from the Wabamun Lake area in central Alberta, Canada, where large CO2 sources and several acid-gas injection operations exist. Results for both drainage and imbibition relative permeability experiments are presented for each fluid and rock type, as well as measurements of the interfacial tension (IFT) between brines and CO2 and H2S at in situ conditions, and correlations of these results with the IFT, measured rock capillary pressure, pore size distribution and mineralogical data. The results allow a comparison between the drainage and imbibition relative permeability character and performance of the two gases, and provide a valuable dataset for the evaluation and simulation of acid gas disposal and CO2 storage projects.
Case Studies: A Practical Approach to Gas-Production Analysis and Forecasting
Authors: Jordan C. L. , Fenniak M. J. , Smith C. R.
Published: December 2007

This paper illustrates a practical systematic approach to determine the reservoir flow characteristics and reserves for both conventional and unconventional gas wells. Currently, there is an industry assortment of production analysis methods ranging from exponential decline and typecurve matching to rate-pressure normalization techniques and detailed production history matching. Through real life cases studies it will be shown that it is possible that a simpler reservoir model, such as a single well completed in the center of a circular reservoir, could be used to represent far more complex reservoirs, and still provide some representative reservoir characterization, as well as accurate reserves analysis and production forecasting. As a result, it possible that engineers and the like can avoid some of the more labor intensive production data analysis (PDA) techniques, and use more a methodology similar in operation to traditional decline.

Case studies and experience presented in this paper will demonstrate that a simple approach of production analysis methods will allow for a) proper identification of flow regimes, b) reliable evaluation of drainage area and OGIP, and c) the prediction of future deliverability and depletion. Case studies will also show that up-scaled and aggregate reservoir properties can provide a real measure of gas well deliverability (therefore a simpler, time-efficient model analysis can be used). Data uncertainty, unconventional gas (i.e. coal bed methane, tight gas, shale gas), stimulation appraisal, and other factors will be discussed in the context of the case studies.
Prediction of Drillstring Fatigue Life Under Axial-Torsional-Combined Vibration
Authors: Chi A. , Zhang J. , Ge W. , Guo B.
Published: December 2007

Vibration of drillstring was found responsible for the severe damage and premature failure of drillstrings during drilling the gas-bearing igneous formations in the Songliao Basin, China. The vibration significantly shortened the life of drillstrings and had a great impact on drilling performance in the area. The objective of this study was to identify the key factors affecting drillstring vibration and develop a control-mechanism to reduce the failure rate of drillstring.

This study investigated the combined effect of axial and torsional vibrations on the damage of drillstring. A computerized model was built to simulate loads from axial and torsional vibrations. An analytical method for predicting the fatigue life of drillstring was developed. The method uses the output from the computerized model. Engineering charts were also generated for typical drilling conditions. These charts have been adapted in a Drillstring Damage Control Program implemented in the Songliao Basin, China.
Production Optimization—A Moving-Horizon Approach
Authors: Nikolaou M. , Cullick A. S. , Saputelli L.
Published: December 2007

Designing fluid injection policies to optimize the production of a hydrocarbon reservoir has attracted considerable interest in recent years. Production policies can emerge from numerical optimization analyses, the solutions for which are most frequently based on optimal control theory. In this paper we argue that (a) a simpler alternative to the optimal control approach may be used, and (b) we present a moving-horizon formulation alternative. We illustrate the proposed approach through several examples.
Through-Tubing Inflatable Intervention Tools and Techniques in a Subsea Well Environment
Authors: Kelbie G. M. , Mackenzie G.
Published: December 2007

With the number of subsea wells increasing so has the requirement to be able to provide lower cost through-tubing live well intervention solutions to a number of well servicing problems. Through-tubing operations on subsea wells are routinely being conducted from a variety of vessels such as monohull or smaller semi-submersible vessels through to larger drilling based rig operations. Many times when performing said remedial or abandonment work on subsea wells the conditions can prove to be extremely challenging to both operator and service provider. Many of the older subsea wells have come to the operating company via a variety of mergers and/or acquisitions and may prove to have a limited history. Often the actual conditions and geometry of the wellbore can be unclear until the subsea well is actually re-entered. However, at this point, the intervention vessel is already on station and incurring daily costs to the operator. In this paper we are going to disseminate several case histories, highlighting the technical and economical advantages that have been achieved in subsea well interventions utilizing through-tubing inflatable intervention tools. Apart from the more recognizable feature of being able to be conveyed into the well on either electric wireline or coiled tubing allowing for live well intervention, the often less perceived advantage of the inflatable type packing element is in its ability to be able to be set in a broad range of both diameters and conditions. Having this ability allows for the operator to have on board the vessel the opportunity to cover many different types of scenarios that may be encountered. This philosophy can markedly reduce the amount of tools required on board to cover a multitude of operations minimizing logistical, storage and cost concerns. One of the presented case histories will highlight how a planned operation prior to load out to plug the completion tubular in order to repair a leaking flowline ended up with the same mobilized tool providing a barrier while being set in the actual subsea tree due to the tubing being found to be parted on entering the well.
Improving Volumetric Sweep Efficiency With Polymer Gels in the Cuyo Basin of Argentina
Authors: Norman C. , Lucia J. De , Turner B.
Published: December 2007

In December 2003, a pilot polymer gel treatment was implemented in the Vizcacheras Field located in Western Argentina's Cuyo Basin. The project included one injection well polymer treatment with the primary objective of improving volumetric sweep efficiency in the subject pattern and, consequently, improving oil recovery. A secondary goal was to reduce water production in the offset producers.

The Vizcacheras Field is a mature waterflood that was discovered in 1965. Upon implementation of the polymer gel pilot in December 2003, field production was 8635 BOPD from 162 producing wells with an average water cut of 96%. The production comes from two heterogeneous fluvial sandstone formations:Papagayos and Barrancas. Approximately 31% of the total oil production comes from the Barrancas formation, the target of this project.

This conformance improvement project began in 2002 with laboratory studies, initial polymer gel treatment design, tracer studies and numerical simulation. The gel chemistry included a medium molecular weight, partially hydrolyzed anionic polyacrylamide polymer crosslinked with chromium acetate. After a monitoring period, positive results were observed in five of twelve offset producers and an expansion project was designed.

The following paragraphs will describe the petrophysical characteristics of the Barrancas formation, including an overview of the field production and waterflood history, as well as the design, implementation, and evaluation of the polymer gel pilot project.
How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?
Authors: Kabir C. S. , Pop J. J.
Published: December 2007

Collection and analysis of gas/condensate fluid samples present considerable challenges. That is because downhole sampling of a gas/condensate fluid, unlike its oil counterpart, does not guarantee retrieval of single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality, the PVT analysis of any fluid sample with an equation-of-state (EOS) model demands that the results are verified with independent measurements.

Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from wellbore-flow modeling of production-test data. Older generation formation testers, those prior to 1990, although yielding comparable results, had larger error bars owing to system limitations in repeatability of both pressure and depth measurements.

We developed a yield-temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multi-reservoir samples, which is particularly useful when rapid assessment is needed over large regions.
Field Application of Combined Kinetic Hydrate and Corrosion Inhibitors in the Southern North Sea: Case Studies
Authors: MacDonald A. W. R. , Petrie M. , Wylde J. J. , Chalmers A. J. , Arjmandi M.
Published: December 2007

This paper details three field applications of combined low dose hydrate (LDHI) and corrosion inhibitor (CI) chemicals in different assets in the Southern North Sea (UKCS) gas producing area. The design and application philosophy is discussed as well as the criteria necessary to manage a safe and efficient chemical transition. The three fields all displayed mid-level degrees of sub-cooling (4 – 8 °C) with operating pressures up to 70 bar with variable water breakthrough. Corrosion was severe in some cases with over 700 ppm of H2S production combined with 1.1 mol % CO2 in the produced gas.

The paper goes onto describe the cost benefits of such applications including increased equipment efficiency, logistical savings of single chemical deployment and lower maintenance costs. In addition improved hydrate and corrosion control was achieved over the incumbent chemical. This approach achieved cost savings, including a saving of $3 million in the first year of application on one of the fields. Environmental benefits have also been realised with reduced chemical usage and discharge and improved environmental profile of the combined products when compared to the originally selected single application chemicals.
From Reservoir to Well: Using Technology for World-Class Results in Trinidad and Tobago
Authors: Samsundar K. , Chung R.
Published: December 2007

The Mahogany field in Trinidad and Tobago was developed as a dedicated gas field with reserves of 2.6 TCF to supply gas to the Atlantic LNG Plant in 1999. At that time the field was the sole provider of gas to the ALNG project. The vision was to ensure that the field was a world class producer that met the demands on the LNG Train 1 market. It was clear from the onset that the only way to deliver this vision was through the use of technology. Even more so since the field is a highly faulted, complex reservoir, that has a thin oil rim.

With over 1TCF of gas already produced, the Mahogany Team is on its way to delivering this result. Technology has been the backbone of the Mahogany field development, with new technology being used from inception through drilling, reservoir monitoring and production. This intimate surveillance of the wells through new technology has generated a wealth of information. Updated simulation models have been generated using this data, which have led to a deeper understanding of the dynamic fluid distribution in the complicated reservoirs. This in turn has been the critical factor in the successful infill development of the field. It is clear that one of the critical success factors in managing the development and exploitation of the field was the use of technology.

This paper will discuss the use of technology along the value chain of first drill to present and will highlight the real benefits of using technology along the way, primarily highlighting the successful use of fiber optic flowmeters, distributed temperature system, acoustic sand detectors and permanent downhole gauges.
A New Approach to Hydraulic Fracturing Modeling—Fully Coupled with Geomechanical and Reservoir Simulation
Authors: Ji L. , Settari A. , Sullivan R. B.
Published: December 2007

Fracturing modeling methods developed for conventional hydraulic fracturing are now being used for unconventional fracturing in waterfracs, water or steam flooding, produced water reinjection, etc. A common feature of these unconventional fracturing processes is the strong interaction among fracture propagation (often with high 3D fluid leakoff), reservoir flow, changes in stresses (poroelastic and thermoelastic effects), and permeability and porosity changes (geomechanical effects) around the fracture. Conventional fracturing models are inadequate under such conditions; moreover, they are also disconnected from well performance forecasting, which makes integrated data analysis difficult.

Therefore, it is necessary to seek a new modeling concept including all these mechanisms and their mutual influences.

This paper describes a method to model hydraulic fracturing with dynamic transmissibility multipliers based on coupled reservoir and geomechanics simulation. The method is the first step in developing a fracturing model fully coupled into reservoir and geomechanics simulation, where the fracture geometry will be also internally calculated from the fracture face displacements in the coupled FEM geomechanical module. The method described here ignores fracture volume but focuses on the effect of fracture on fluid flow and geomechanics in reservoir by introducing pressure/stress dependent dynamic transmissibility multipliers and treating them as a property of the matrix. This approach allows modeling fracture propagation, dynamical multiphase fracture conductivity, clean-up, and pre- and post-frac well performance in a changing stress, pressure and temperature environment, all in a unified manner.

This paper also discusses the strategy of coupling hydraulic fracture propagation, reservoir and geomchanics simulation, resulting in a method to improve the stability of the dynamic hydraulic fracture propagation in coupled reservoir and geomechanics simulation.

The case studies in this paper confirm that the strategy and the method to model dynamic hydraulic fracture propagation coupled with reservoir and geomechanics simulation is feasible, flexible and reliable. It is easy and convenient to implement in conventional reservoir simulators and coupled reservoir and geomechanics simulators (such as GEOSIM).
The Effects of Temperature and Potential Determining Ions Present in Seawater on Oil Recovery From Fractured Carbonates
Authors: Tweheyo M. T. , Zhang P. , Austad T.
Published: December 2007

This paper is one among others on IOR studies in carbonates regarding the effects of potential determining ions on the wettability alteration, and the subsequent effect on oil recovery by spontaneous imbibition. Besides the oil properties, water-composition and rock properties are also important to wettability. It has been documented in previous related work that SO42- and Ca2+ are strong potential determining ions and greatly influence the surface charge of carbonate rocks.

This work concentrates on evaluating the effect of various ratios of the two ions on wettability alteration and spontaneous imbibition at various temperatures. The ionic concentrations were varied both in the initial and imbibing brines. Imbibition tests were performed at 40, 70, 100 and 130°C using out-crop chalk samples, which were aged for 4-6 weeks at 90°C in a modified crude oil with an acid number of 2.0 mgKOH/g. Additional tests were carried out to evaluate SO42- as a wettability modifier without the presence of Ca2+ and/or Mg2+.

The results show that the three divalent ions Ca2+, Mg2+, and SO42-, which are naturally present in seawater, are important in changing the surface charge of chalk and are more effective when they are all present in solution in favourable ratios. They seem to play different roles in the two processes: wettability alteration and spontaneous imbibition, both of which are temperature-dependant. Sulfate adsorption is the key factor in the wettability alteration, but Ca2+ and Mg2+ seem to play a promotional role apparently by lowering the characteristic temperature for the wettability shift from neutral to moderate water-wet.

Wettability alteration and improved oil recovery have also been linked to the stability of the wetting film, attraction forces and activation energy of the process in relation to the [Ca2+]/[SO42-] ratio, and temperature through measurement of contact angles on calcite crystals. Imbibing brines with higher ratios seem to require lower activation energy to establish a liquid-rock equilibrium interface to initiate spontaneous imbibition. The brines also have stronger attraction forces to calcite and require less work of adhesion than brines with low ratios, or completely depleted in Ca2+ and Mg2+. Brines with higher [SO42-] seem to possess more wetting effects and increased potential to spread as the temperature increases.
Numerical Investigation on Hydraulic Fracture Cleanup and Its Impact on the Productivity of a Gas Well With a Non-Newtonian Fluid Model
Authors: Friedel T.
Published: December 2007

To exploit the substantial tight-gas resources worldwide, hydraulic fracturing is, for many cases, economically a viable option. However, despite the state of the art techniques such as multiple fracturing of horizontal wellbores, the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality, strong stress dependency in permeability, hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one, related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics, was rarely taken into account before and is the subject of the current paper.

For this purpose, an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator, capturing the yield stress of common polymer gel.

The model is applied to typical cleanup scenarios. Using the model, it can be shown that the residing, non-recoverable gel (typically 50%) decreases the fracture conductivity and, hence, the production potential of a fractured gas well. This coincides with experiences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fracture, gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in analytical studies, there is no sharp interface between the residual gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of fracture cleanup processes and, hence, an improved understanding of formation damage processes in fractured wells. Furthermore, the model enables the design of more successful fracture treatments in tight-gas reservoirs.
Real-Time Production Optimization of Offshore Oil and Gas Production Systems: A Technology Survey
Authors: Bieker H. P. , Slupphaug O. , Johansen T. A.
Published: December 2007

The information flow used for optimization of an offshore oil production plant is described. The elements in this description include data acquisition, data storage, processing facility model updating, well model updating, reservoir model updating, production planning, reservoir planning, and strategic planning. Methods for well allocation, gas lift and gas/water injection optimization and updating of the models are reviewed in relationship with the information flow described. Challenges of real time optimization are discussed.
Applications of Fiber-Optic Real-Time Distributed Temperature Sensing in a Heavy-Oil-Production Environment
Authors: Goiffon J. , Gualtieri D.
Published: December 2007

Advances have been made to temperature monitoring with the application of distributed temperature sensing with fiber optics over the length of the wellbore to provide data for analysis of the well conditions. With this method, an optical fiber to monitor temperature over the entire length of a well is installed. Custom visualization and analysis software then uses the distributed temperature sensing data that is retrieved to perform analysis of well conditions in environments in which heat management is needed.

The capability to retrieve real-time data allows use of visualization and analytical software to provide rapid qualitative analysis prior to obtaining final quantitative results. This process enables improvement of heat management in heavy oil wells by detection of problem areas within the well. The improvements are provided by the capability to compare a large number of data sets.

The fiber-optic technology was initially deployed in a steamflood well in Bakersfield, California over ten years ago.1 Since that time, the technology has been applied in many different producing environments and has proven that monitoring of downhole conditions can provide valuable information for production assessment.

This paper will discuss the significant benefits gained from using this technology in heavy-oil monitoring scenarios.
Advanced Drilling Using a Dual-Bit System
Authors: Gopalsing P. M.
Published: December 2007

In conventional drilling a majority of drilling problems occur during tripping such as key seating and wall sticking. This leads to increase in rig time hence cost is unnecessarily high, especially in deep sea drilling.

Conventional drilling techniques use rotary drill bits which need to be replaced depending on the formations encountered. If the formation is very hard, the bit has to be replaced by a diamond bit. This change of bit requires unnecessary increase in trip time and hence rigs cost. This trip time which can even take a day especially for deep wells and can be eliminated by using a novel method of a drill bit called a "Piggy Back Dual Bit" system.

This paper deals with the design and operation of such a novel Piggy Back Dual Bit system.

This new drill bit system has a tricone bit on the outside and a PDC or diamond studded bit inside. Both the tricone bit and PDC bit are expandable. When hard formations are encountered, the tricone bit is expanded by applied pressure to the mud which engages a latching mechanism in the BHA. By this action also the expandable PDC bit is forced out. The entire expansion mechanism is hydraulically actuated, by the pressure from fluid flowing through the bit. The drilling activity is now controlled by the PDC drill bit doing the drilling through the hard formation, while the tricone bit is now piggy back on the PDC drill bit doing no work at all, other than reaming a bigger hole.

Thus an entire hole can be drilled conveniently without frequent tripping operation to change the bit. Maximum efficiency can be achieved by this mechanism during drilling.

In petroleum industry rig time plays very vital role. By adopting such innovative method as mentioned above tripping time can be substantially reduced.