bluuebunny/crossref_metadata_2025 huggingface dataset:
Leak Location in Subsea Umbilicals
Authors: Stebbings T. F. , Alexander P. D. , Evans K. D. , McEwan I. K. , Ryan N. J. , Marstrand J. , Riiser K.
Published: December 2007

Leaks in subsea umbilical systems are highly problematic as they are difficult to locate and the eventual egress of fluid may be a considerable distance from the actual line failure due to the presence of additional outer sheath(s).

However, in late 2006, by applying their knowledge of how leaks affect the pressure and flow characteristics in a pipeline, Brinker Technology developed an analytical tool which enables them to calculate the approximate location of a leak in a single line of an umbilical bundle. This technique was effectively put to use in November 2006 when, on behalf of Norsk Hydro, Brinker Technology were able to successfully calculate the location of a leak in an Ormen Lange main umbilical.

Further to an analytical leak location assessment Brinker can deploy their proven core product, Platelet Technology®, to seal the leak and add further assurance and a greater degree of accuracy to the location estimate.

Platelet Technology® involves the remote injection of discrete particles known as "Platelets®" into a pipeline which are carried to the leak site due to the flow. When they reach the vicinity of the leak fluid forces entrain them into the leak and hold them against the pipe wall thus facilitating sealing. By doping the Platelets® with a radioisotope prior to deployment an ROV mounted detection device can then be used in this region to pin-point the exact location of the entrained Platelets® and hence the leak.

Both these techniques, the analytical leak location tool and Platelet Technology®, will be presented in this paper with emphasis on the recent operation for Norsk Hydro.
The Equilibrium Free-Gas to Liquid Ratio (FGLR) Method
Authors: Cunningham Peter , Krijger Giel
Published: December 2007

The equilibrium free-gas: liquid ratio (FGLR) method is a new method for calculating gas production rates within a material balance model. The method calculates the reservoir FGLR at which there would be no overall movement of the gas-liquid contact. It is then assumed that the reservoir is tending towards such an equilibrium position i.e. the reservoir FGLR converges towards the equilibrium FGLR. Given an estimate of the rate of convergence and a forecast of liquid production (from decline analysis, for example), these assumptions are sufficient to give an approximate forecast of a reservoir or well gas production profile.

The method can be used to forecast associated gas production from oil-fields with significant gas-caps, especially thin oil-rims, for which wells are usually drilled close to the original gas-oil contact. It gives a gas production forecast broadly comparable to a decline-curve oil production forecast. Unlike the Muskat method, it does not depend on unmeasurable reservoir-scale relative permeabilities.

The method has been been mathematically derived from some basic assumptions about average reservoir behaviour. The validity of the assumptions and the method have been checked by comparison with historical production data from eight oil-rim reservoirs. The method has been successfully in use for reserves evaluation for a group of producing Nigerian oil-rim fields for the past four years. The evidence suggests that the method is a useful and robust approximation, but further validation would be very useful.

If further validation confirms its general validity, then the equilibrium free-gas:liquid ratio method would become a useful part of material balance theory and calculations for oil-fields with associated gas production.
Competence-Based Management for Recruitment, Deployment, and Commitment
Authors: McAllister Douglas
Published: December 2007

Competence is a much-used expression in the present business environment but surprisingly, it is a concept which is commonly misunderstood. In support of recruitment, competency based systems have been around for many years. Many businesses have used competency assurance systems, often driven by quality management systems, for some time. Internal staff assessment processes using competencies as their measurement system are also quite commonplace

Part of the difficulty many people have with competence assessment is that it tends to be something ‘done to them’. Individuals rarely see any personal advantage to having their competency assessed or any advantage to contributing to the assessment of others. It is often viewed as a necessary evil that the business needs, perhaps to sell into certain markets or to keep up with the competition. It can be seen as a business overhead, a non-value adding activity and worst of all perhaps, a paper chase.

When competence based systems are viewed in this way, organizations are simply not getting the value that such an approach can yield. Viewed as a paper chase, competence assurance is an overhead, a cost and, other than ‘ticking the box’ in your quality management system, does little for the efficiency of you business.
Estimation of Variable Fluids-Mixture Density With 4D NMR Logging
Authors: Minh Chanh Cao , Caroli Emmanuel , Sundararaman Padmanabhan
Published: December 2007

Whereas matrix density is known from core analysis or spectroscopy logging, so far no technique is available to estimate the apparent fluid density that the density log measures. In wells drilled with OBM, the near-wellbore fluids composition and distribution can be very complex. Yet, the current practice to compute density porosity is to use an ad hoc constant fluid density. This could lead to erroneous estimation of porosity. For example, in a 30 pu sandstone drilled with OBM, every 0.1 g/cm3 error in fluid density leads to 1.5 pu error in porosity.

Numerous studies of near-wellbore fluids with 3D NMR (T1, T2, D) maps from NMR logging tools have shown a very complex fluids mixture that can include water, oil, OBM, and condensate/gas. However, the map acquired at a single depth of investigation (DOI) might not represent the fluids mixture that the density tool measures.

The advent of radial fluid profiling with advanced magnetic resonance tools provides the needed fourth dimension—radial information that can be inverted jointly with conventional 3D NMR to unravel both fluids mixture and radial distribution. Because the near-wellbore NMR region closely matches the density region in both radial and axial directions, the two sets of data form "perfect" consonant volumes. Continuous 4D NMR maps are thus ideal to estimate the variable mixed fluids density. This value can be expressed as the double integration of all individual fluids detected by NMR weighted by the geometrical radial response function of the density log. The inner integration estimates the mixed fluids density. The outer integration computes it at 95% radial response of the density log.

Examples are shown in which variable fluid density confirms subtle fluid changes recorded by density-neutron logs in sandstone formations offshore West Africa. These sands have variations in grain size and shaliness that control permeability and therefore the OBM invasion. Another example shows large porosity deficits when the contrasting fluids density is large, such as gas invaded by OBM. In all cases, density porosity computed with the variable fluid density agrees with local field knowledge and other methods. A side benefit is the reconciliation of NMR and density porosity discrepancy, because density porosity is often the reference to which NMR logs are judged.
Use of Advanced Pressure Transient Analysis Techniques To Improve Drainage Area Calculations and Reservoir Characterisation: Field Case Studies
Authors: Du Kui-Fu
Published: December 2007

This paper presents several field examples of applying two independent methods of increasing tested area estimation and improving reservoir characterisation, based on utilising the entire well test history rather than just a single pressure build-up (PBU) or drawdown period. The two techniques are the pressure-rate deconvolution and the conventional pressure transient analysis (PTA) based "shrinking box" approach. A large number of the field cases are studied to illustrate their benefits as well as procedures for the minimum tested area calculations under various reservoir geometries. These field examples demonstrate that both methods, if carefully used, can yield almost identical radii of investigation derived from the entire test sequence and that the deconvolution technique can reveal additional reservoir information which may not be detected otherwise.
High-Performance Water-Based Insulating Packer Fluids
Authors: Ezzat A. M. , Miller J. J. , Ezell R. G. , Perez G. P.
Published: December 2007

Deepwater production well design and equipment installation presents a host of challenges for operators. One of the major problems is the uncontrolled heat transfer to outer annuli and heat loss from the production tubing which can be detrimental to the integrity of outer annuli. This can reduce the well productivity in case deposition of paraffin and asphaltenes occurs, and could contribute to the formation of gas hydrates. Vacuum insulated tubing (VIT) has had limited success but has numerous drawbacks (e.g., cost, breakdown, "hot spots" at connection joints, etc.). To avoid these problems, high viscosity insulating packer fluids (IPFs) have been employed to thermally isolate production tubing from the exterior pipe and to provide the required hydrostatic pressure.

Numerous combinations of both water- and oil-based materials have been utilized in attempts to devise a cost effective solution. Successful fluids have a low inherent thermal conductivity, remain viscosified or gelled to eliminate convective heat transfer and are expected to have service lifetimes of up to 20 years. However, the current state of the art falls short of meeting these objectives. Oil-based IPFs often have low thermal conductivity, but cannot be weighted, suffer from toxicity and often come with HSE issues. Water based IPFs can be weighted, but generally have temperature stability limitations > 250°F (121.1°C) as well as higher inherent thermal conductivity than oil-based IPF's.

Through extensive investigation of multidisciplinary technologies, a superior performing aqueous-based IPF was developed for elevated temperatures. The novel system delivers performance beyond conventional systems of comparable thermal conductivity (k). The new system covers a density range of 8.5 - 14.6 lb/gal (1.02 – 1.75 sp.gr.) and displays heat transfer measurements between 0.12 - 0.17 BTU/hr ft°F. High-temperature static aging tests have demonstrated superior gel integrity with no phase separation or syneresis after exposure to 280°F (137.8°C) for three months. Parallel testing at 325°F (162.8°C) has shown similar success. The new fluids are hydrate inhibitive, pass oil and grease testing, and can be made environmentally acceptable for the Gulf of Mexico. Laboratory data generated under deepwater simulated conditions will be presented and discussed in this paper.
Cost-Effective Lateral-Junction Isolation in High-Pressure Air-Injector Wells
Authors: Asbill Steven , Webb Alan , Rogers Hank , Adkins Darrell
Published: December 2007

High-pressure air injection (HPAI) has proved to be a valuable improved oil recovery (IOR) process in fields where other recovery processes are uneconomical.

As in every upturn in the oil and gas industry, hydrocarbons in unconventional, tight, mature, and other challenging formations attract added interest when the economics appear to be positive. With more efficient technology to extract greater percentages of the reservoir, operating companies are re-entering old fields and successfully increasing production.

When exploiting existing wells, costs can be reduced by entering accessible main wellbores and sidetracking to new areas of the reservoir. In those fields where the production has naturally declined over the years, some type of injection program may be required. In certain situations, available injection resources and infrastructure will lead to a high-pressure air injection (HPAI) model. HPAI is an extremely corrosive and hostile environment, so ensuring proper well construction and isolation of the lateral junction is imperative. At the same time, the economics of these wells require a simple, cost-effective solution that is readily available for a high-volume field program.

This paper reviews solutions for these lateral-isolation instances and presents a simple, efficient and cost-effective system.
Technical Breakthrough in PCPs' Scaling Issue of ASP Flooding in Daqing Oil Field
Authors: Gang Cao , He Liu , Guochen Shi , Guoqing Wang , Zhongwen Xiu , Huaifeng Ren , Ying Zhang
Published: December 2007

The ASP flooding Pilot tests in Daqing Oilfield commenced in 1982. And since 2005, APS flooding has entered commercial application in several main oil companies. Although the recovery rate can be improved by 20% over that with water flooding, severe scaling in downhole equipment turned out to be the biggest issue for artificial lift systems in ASP producers. Sucker rod failure rate was extremely high for beam pumping wells. As for PCP system, its running life was relatively the longest one among all lifting methods, but it was still not economic. Severe scaling on the surface of pump and string was the major factor causing drastic oscillation of operating load.

Study indicated that surface energy of the material has great effect on scaling degree. Scale was easier to be formed on the materials with higher surface energy than that with lower surface energy. Using higher surface energy coating material was the main reason resulting in the severe scaling on traditional PCP rotors in ASP area. In that case, a novel ceramic coating technique was developed to decrease the coating material's surface energy to a much lower degree, and to prolong PCP wells’ running lives effectively.

Experiments showed that, elastomer's visco-elastic effect enhanced the periodic oscillation of PCPs’ operating load leading to high rod fatigue failure rate. In addition, interference fit design between rotor and stator also has certain influence on PCPs’ operation load. Based on the above studies, stator's surface modification technique and optimum interference fit design technique were developed to improve PCP's operation status. As an auxiliary treatment, a special chemical scale remover was developed to decrease the scaling degree of tubing and rod string.

These novel techniques have been applied in 58 PCP wells, the average running life increased from several months to more than one year. PCP systems’ operating status was improved effectively, and rod fatigue failure rate was decreased drastically.
Joint Industry Project: Improvised PPE Informatics Integrity Reducing Occupational Risks
Authors: Knight S. J. , Klinger Edward
Published: December 2007

This paper presents the background, approach and overview of the Phase 1 results of a five-phase Joint Industry Project proposal. Research commenced in 2006, to establish the need and methods to reduce Oil & Gas workforce exposure risks. The reports prepared throughout Phase 1 will become the shared property of the JIP participants. Not all details can therefore be disclosed within this paper. Presentation of the paper is intended to offer the opportunity to operators and organizations to be directly involved or associated in other ways with this initiative.

The advancement of technology in the area of PPE, integrated communications and emergency response systems will contribute to safety in petroleum industry areas such as; worker confidence in self and co-worker safety; remote vital signs health monitoring in conjunction with personnel tracking; non-reliance on human reaction and training for respiratory protection in toxic atmospheres; remote audio-visuals, relevant scenario data acquisition and optimized dissemination for effective emergency response.

The JIP is focused on bringing together all technologies within a single integrated solution. It will develop further the concept established during Phase 1, taking account of the established PPE performance standard criterion, to protect personnel while effectively and efficiently communicating reliable data for situational awareness. It is being shown that significant risk reduction benefits are achievable at all upstream E&P sites and facilities, whether in arctic or tropical locations and whether subject to technological hazards between construction and HPHT sour operations. Reducing the risk of incurring casualties during emergency response is a predicted achievable project objective.

Only by taking a green-field approach was it possible to identify the problems associated with existing PPE and communication methods so as to target a fully integrated solution that isn't currently available.
Quantifying Non-Darcy Effects on the Productivity of a Cased-Hole Frac Pack (CHFP) Well
Authors: Ouyang Liang-Biao
Published: December 2007

Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. So could the well performance under a specific type of well completion.

There are many different completion options available in the industry, including open hole, slotted liner, inflow control devices, intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen, ECPs, gravel pack, and frac pack, etc. Under most circumstances, the completion for a new well is selected based on its cost, performance, sand control potential, water shut-off possibility, reliability, and so on. An appropriate well completion design requires an accurate prediction of well performance.

Unfortunately, well performance prediction models available in current commercial packages need to be improved for certain well completion types to account for the details of fluid flow in the completion. One of the completions falling under this category is cased-hole fracpack completion where fluid flow would suffer because of the bottleneck effects associated with fluid flow in fractures and fluid flow along perforation tunnels. In particular, for high rate gas wells, non-Darcy flow would play a significant role for fluid flow along perforation tunnels, in fractures and formation, and thus would have substantial negative impacts on well productivity.

Appropriate quantification of the non-Darcy flow effects is critical for accurate well performance modeling for the cased-hole fracpack completion. In the present paper, the non-Darcy flow impacts will first be discussed for fluid flow in fractures, in formation, and along perforation tunnels. Methodologies to quantifying the impacts will then be discussed and the procedure to account for the effects in well performance modeling will be proposed. A series of sensitivity studies will then be conducted to illustrate the relative importance of key parameters on the non-Darcy flow. Finally, the new approach will be applied to a fictitious field to demonstrate what the difference in well productivity prediction would make with and without reasonable account for the non-Darcy flow effects.
Integration of Production and Process Facility Models in a Single Simulation Tool
Authors: Morales Fernando L. , Velázquez Juan Cruz , Hernandez Aarón Garrido
Published: December 2007

Traditionally in the upstream business, operational decisions are made separately at the reservoir, production and surface facility levels, using only their respective knowledge, experience and engineering tools without limited coordination between them, sometimes bypassing important considerations from other components of the overall production system, outside of their specific domain. For example, a common practice in the oil industry is to generate a production forecast derived from a reservoir-based model, without taking into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity, for example, could impose significant limitations over the well and surface network performance that could impact long term field management plans if they are not properly identified and solved.

PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13,100 BOPD from 10 fields (mostly gas and condensates, but also oil fields) through 69 wells using 6 process facilities and its corresponding pipeline network. Built more than 25 years ago, this PEMEX E&P facility, originally designed for much higher gas and liquid rates than the current ones, faced several slug and counter-pressure problems arising from over- and under-capacity of in its current surface infrastructure. This work describes how a team of reservoir, production and process engineers, developed and implemented a data, simulation and analysis workflow to identify the well-network-process system's major bottle necks and made recommendations of several low cost optimization alternatives to overcome them. The project's results of implemented recommendations increased production in excess of 2,000 BOPD, with no additional investment, and reduced the asset's operational cost by more than USD$ 600,000 USD a year. This simulation tool also proved to be very valuable for early identification of well optimization opportunities, strategic planning and informed decision making, considering the size of the full well-surface facility system.
Rapid and Low-Cost Methodology to Obtain an Updated Compositional Model of Produced Fluids Using Separator Discharge Data Analysis
Authors: Morales Fernando L. , Velázquez Juan Cruz , Hernandez Aaron Garrido
Published: December 2007

Fluid characterization data used to build representative reservoir fluid models for reservoir and production engineering is generally scarce and very costly, due to the expense of fluid sampling and analysis and, operational related problems of well intervention. The problem turns more dramatic when the field to be studied has been producing for some time and its bottom-hole pressure has reached the bubble point. In those cases, initial reservoir fluid data is more difficult to be used as some portion of the hydrocarbon's heaviest or lightest components, whether oil or gas is produced, may have been left in the reservoir and initial PVT data is no longer valid or very difficult to match to current fluid behavior.

One of the most common practices of obtaining fluid data is by taking well bottom-hole samples, or by obtaining surface oil and gas mixture samples and analyzing them in the lab using recombined methods. Due to the costs involved, including loss of time and production, operating companies do not obtain fluid data with the required frequency. Accordingly, engineers are left with the only option of using non-updated or insufficient data that will affect the outcome of their simulation studies.

This work describes a rapid and low cost methodology to obtain an updated compositional model for produced fluids using gas chromatography, oil characterization and GOR from analysis of the separator fluid discharge. The required samples are easily collected with low cost to the operating company.

Then, a case history is shown where compositional fluid models obtained with the proposed method are used in well, surface network and process facility simulation models, with excellent results. A comparison of field data against the simulation model results is also shown.
A Dynamic Wellbore Modeling for Sinusoidal Horizontal Well Performance with High Water Cut
Authors: Tang Yula , Wolff Martin , Condon Patrick , Ogden Katharine
Published: December 2007

The Banzala Field (Block 0, Angola) has produced oil with horizontal wells and ESP's as the artificial lift method for more than seven years. These wells were drilled with large sinusoidal undulations intentionally to cut the pay section a number of times. Banzala "A" horizontal wells underperformed expected production, possibly due to downhole slugging. In addition, declining reservoir pressures, rising GOR, and rising water-cut have also adversely affected production.

The objective of this simulation study of wellbore transient flow is to understand past production performance and to find ways to mitigate adverse well behavior. Simulation showed that low ESP efficiency could be related to down-hole slugging. GOR was the most significant factor for slugging and increasing water cut made slugging worse. The sinusoidal wellbore trajectory was studied to optimize ESP operating conditions. It was found that reducing sinusoidal amplitude by half and flattening the heel-end entrance angle from 79 deg. to 86 deg. would suppress slugging significantly.
Mini-DST Applications for Shell Deepwater Malaysia
Authors: Daungkaew S. , Harfoushian J. H. , Cheong B. , Akinsanmi O. , Yeo J. , Toulekima S.
Published: December 2007

Exploration and appraisal campaigns for deepwater environments are a continuous challenge in today's operations. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be put in place. New technology, real time monitoring and integrated reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of vertical heterogeneity and varying layer flow properties.

Wireline formation testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability, anisotropy, skin factor, vertical connectivity and zonal productivity index are additional reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT).

Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA), borehole images, and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis method for mini-DSTs is also introduced.

Reservoir parameters obtained from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information such as petrophysical data, core analysis, well tests, production logs, and single probe wireline formation tests in order to obtain accurate interpretation results of highest consistency.

Field examples will be discussed which show that smaller scale pressure transient tests often have an advantage over full scale well tests testing in terms of providing detailed layer flow behavior, vertical connectivity and flow potential in thinly bedded environments. It will also be noted that the radius of investigation of a mini-DST is limited, typically within tens of feet. This paper demonstrates using field examples that reservoir boundaries can be detected when sufficient radius of investigation is achieved. In addition, the understanding of limitations and advantages will allow the proper selection of test types in order to meet specific objectives and maximize the full potential use of acquired data for field development plans in thinly laminated deepwater environments.
Light Well Intervention in the Asgard Field (Norway) as a Tool for Improved Reservoir Management
Authors: Viken V. , Hovde E. , Sletfjerding E. , Storoe P. A. , Mjaaland S. , Sand G. A. , Vassenden F. , Lerdahl T. R.
Published: December 2007

The Asgard licence, operated by Statoil, has been a major user of light well intervention (LWI) services since 2003. Based on the value of the results, this subsea field will continue using LWI as a reservoir management tool in the future. The main field, Smorbukk, is a high temperature gas condensate discovery that is developed with 20 commingled producers and 12 gas injectors. The reservoir complexity, commingled production and injection strategy for the wells has necessitated regular data acquisition. The data has been implemented in the reservoir models, resulting in improved reservoir management.

During the 4 years of LWI operations on Asgard, the scope of work has increased. The operational experience gained has developed a potential for further development of LWI. Integrated operations (IO) have increasingly been applied throughout the LWI campaigns during witnessing and quality control of well operations (e.g. production logging). Offshore to onshore communication of real time data and video-conferencing have been made possible.

The development of light well intervention methods has made data acquisition in subsea wells more economically attractive.

The data acquired in the campaigns has lead to:

– Improved Recovery based on better zone control for injectors and producers. – Identification of candidate intervals for closing off high GOR zones and directing injection gas into optimal zones. – Increased confidence in reservoir model as basis for infill wells.

Improvements through use of IO:

– It became possible for an onshore production engineer to perform an offshore day shift without travelling offshore. – IO has improved the speed and quality of decisions made through more effective involvement of onshore specialists. – IO has reduced the cost of the overall programme.
Non-Darcy Flow Effects in Dual-Porosity, Dual-Permeability, Naturally Fractured Gas Condensate Reservoirs
Authors: Ramirez B. , Kazemi H. , Ozkan E. , Al-Matrook M.
Published: December 2007

This paper addresses the retrograde condensation behavior in natural fractures and in the near wellbore region of a naturally fractured reservoir (NFR). The study includes the combined effect of non-Darcy flow in presence of retrograde condensation and wellbore damage on pressure transient analysis of naturally fractured reservoirs. A single well compositional model was constructed and used to evaluate both the early-time and late-time characteristics of the pressure transient data.

In naturally fractured reservoirs the high velocity region could be substantially beyond the near wellbore region because of the narrowness of the fractures. To assess this situation, draw-down, build-up and multi-rate tests were simulated in rich gas and lean gas condensate reservoirs. It was concluded that the gas condensation in the near wellbore region significantly increases the calculated skin factor beyond the physical damage.
Offshore Natural Gas Liquefaction Process Selection and Development Issues
Authors: Wood David , Mokhatab Saeid , Economides Michael J.
Published: December 2007

Liquefying natural gas on an offshore facility servicing an underlying gas field has yet to be sanctioned anywhere in the world, in spite of several feasibility studies demonstrating its potential viability. The perceived risks associated with deploying unproven technology in a high construction cost and volatrile gas price environment have so far inhibited offshore liquefaction projects. Such technology however has the potential to unlock substantial volumes of remote and otherwise stranded natural gas for commercial exploitation.

With strict no flaring aspirations in many countries discovering associated gas can pose obstacles to developing an oil field if no gas utilization strategy is commercially viable. Key issues for offshore gass liquefaction processes are: compactness (low weight–small footprint), ease of operation, process safety, and efficiency.

Particular attention is paid to the lower-efficiency turboexpander processes for plant capacities up to 3 million tons per annum (MTPA, about 0.43 Bcf/d). These cycles offer several advantages over the alternative optimized cascade and mixed refrigerant (MR) liquefiers..
Experimental Validation of Pore-Level Calculations of Static and Dynamic Petrophysical Properties of Clastic Rocks
Authors: Jin G. , Torres-Verdín C. , Radaelli F. , Rossi E.
Published: December 2007

We present an integrated approach to calculate fundamental macroscopic static and dynamic properties of porous media, including absolute permeability, formation factor, relative permeability, capillary pressure, and resistivity index. The calculations are based on high-resolution three-dimensional (3D) digital images of actual clastic rocks acquired with X-ray computed tomography (CT). Pore-level simulations of single-phase fluid flow and electrical conduction are performed using the lattice-Boltzmann method and diffusion random walks, respectively. Two-phase immiscible fluids are geometrically distributed into the pore space of the synthetic rock using a simple percolation algorithm while enforcing capillary equilibrium. These simulations serve to calculate effective medium properties of macroscopic rock behavior that can be used to improve both the interpretation of well-log measurements and the prediction of multiphase flow properties.

To test and validate our pore-scale model, we consider three micro-CT images of quartzose sandstones with different petrophysical properties to perform both laboratory measurements and pore-level calculations. The calculated permeability is in good agreement with the corresponding laboratory measurements for clean sands, while it differs for the shaly-sand sample. For both cases, the computed formation factor is consistent with laboratory measurements. For the case of two-phase simulations of water-wet conditions, the derived capillary pressure, relative permeability and resistivity index closely agree with experimental measurements when immovable fluid saturations of oil and water are taken into account. Our simulations show that calculations performed on a small rock sample may not always be representative of heterogeneous rock formations. We also find that the amount of clay-bound water should be accounted for in pore-level petrophysical studies, especially for rocks containing a significant amount of clay minerals. Higher image resolution than available is needed to accurately quantify macroscopic petrophysical properties of such complex rock samples.
Multiphase Non-Darcy Flow in Proppant Packs
Authors: Barree R. D. , Conway M. W.
Published: December 2007

This paper builds on a model for single-phase non-Darcy flow in porous media presented in SPE 89325.1 In this work the generalized equation for single-phase non-Darcy flow is extended to multiphase flow conditions. Laboratory measurements of gas-water flow were conducted in several flow cells to determine relative permeability curves and the non-linear relationship between individual phase flow-rate and induced potential gradient over a wide range of input fractional flow conditions and over a range of Reynolds Numbers (Re). A model is presented to predict multiphase non-Darcy flow in porous media that is applicable to high-deliverability reservoirs and hydraulically fractured wells.
Fluid Movement Measurements Through Eccentric Annuli: Unique Results Uncovered
Authors: Moran Larry , Savery Mark
Published: December 2007

Historically, a cement job was considered successful if the casing could be centralized and if high flow rates could be maintained. Today, however, there are more situations where one or both of these criteria are difficult to satisfy. Centralization in highly deviated wells is often challenging, and wells with low fracture gradients place a ceiling on pump rate. Better understanding of fluid movement through eccentric annuli over a wide range of casing standoffs and flow rates is essential for proper cement placement. In addition, being able to predict where cement slurry is located around the casing is very important. For instance, with an eccentric annulus there is no guarantee that cement returns at surface/mud line means complete cement coverage around the casing. Annular fluid velocities can be quite different between the wide and narrow portions of an eccentric annulus. There currently exists limited measured data on flow through annular sizes common to primary cementing operations.

Therefore, a full suite of physical testing was performed to find differences in velocities and flow rates on the wide side vs. the narrow side of a true annulus. Nine models were built, each taller than two meters and each with unique annular geometries. The annular sizes chosen are common to primary cementing operations. The flow area was divided at the top of each model to capture wide and narrow side flow variations. The weight of recovered fluid vs. time was recorded and used to determine flow rates and velocities on both sides. In total, over 250 runs were performed in typical annular geometries with pump rates from 1 bbl/min to 7 bbl/min, fluid rheologies from water-thin to highly viscous, and standoffs from 50% to 85%. While most results verified current industry best practices, other results were quite unexpected, for instance, higher annular velocities on the narrow side under certain conditions. A comprehensive analysis of these results and an appraisal of their potential benefits are presented.
New Constant-Rheology Synthetic-Based Fluid Reduces Downhole Losses in Deepwater Environments
Authors: Rojas Juan Carlos , Bern Peter , Plutt Louise Jacobson , Romo Louis , Greene Bob , Irby Roger , Trotter Neil , Dye Billy , Sharma Nitin
Published: December 2007

Drilling in deep water environments, such as the Gulf of Mexico (GoM), presents the potential for a variety of wellbore and operational problems. Wellbore stability, rates-of-penetration (ROP), hole cleaning, and pressure management are but a few of the key operational parameters affected by the choice of drilling fluid for a given well. Synthetic-base muds (SBM) provide excellent wellbore stability and maximum ROP, particularly in combination with PDC bits. Conversely, management of equivalent circulating density (ECD), pump initiation and surge pressures are more difficult to control with SBM due to the effects of temperature and pressure on rheological properties. The inability to effectively control these drilling parameters can result in catastrophic lost circulation events, which negatively impact operating costs arising from non-productive time (NPT), as well as the high unit cost of the SBM.

This paper highlights the development and application of a new constant-rheology synthetic-based mud (CR-SBM), designed to overcome the problems associated with pressure management when using SBM in deepwater operations. Unlike conventional SBM, this new fluid exhibits a "constant rheology" profile under the conditions encountered in deepwater operations. With the fluid's constant rheology profile, downhole surge pressures and ECD are minimized, thus reducing the frequency and severity of lost circulation events. In addition, the CR-SBM has consistently facilitated delivery of hole cleaning and barite suspension objectives in directional wells.

The CR-SBM presented in this paper is unique in the sense that the near constant profile of key rheological properties was achieved using organophilic clay and without the use of special emulsifiers. In general, the components of the CR-SBM are the same as conventional SBM. Case histories are presented that demonstrate the degree to which the new CR-SBM increases deepwater operational efficiency by reducing downhole mud losses and non-productive time.
The Use of a Fully Coupled Geomechanics-Reservoir Simulator to Evaluate the Feasibility of a Cavity Completion
Authors: Zuluaga E. , Schmidt J. H. , Dean R. H.
Published: December 2007

Cavity completions have been widely used to increase productivity from non-conventional sources such as coalbed methane reservoirs and "heavy" oil from weakly consolidated formations. In the 1990s, the technique was applied to conventional wells where massive sand production was allowed with the objective of creating a cavity. The benefits expected from a cavity completion are four-fold: 1) increase in PI by reducing skin, 2) increase in effective wellbore radius 3) creation of an enhanced permeability (dilatant) zone near the wellbore, and 4) decrease in pressure drop near the wellbore to values below the critical threshold for sanding.

Even though there are analytical tools available for predicting the initiation of sanding for simple well configurations, there are very few models that are capable of predicting cavity stability or cavity growth for general field applications. This paper introduces results from a fully-coupled geomechanical/reservoir simulator, GMRS®, which predicts cavity geometry evolution, sanding rates, cavity stability/instability, and production enhancement because of the creation of a cavity.

In this study, GMRS® is used to investigate the feasibility of a cavity completion in a well located offshore West Africa. This well started producing moderate amounts of sand in 1993. GMRS® is history matched with historical production data prior to sand predictions, and is used to investigate cavity initiation and growth for the well. An axisymmetric model is used with the reservoir treated as a poroelastic-poroplastic material with hardening. Porous flow is modeled as a black-oil two phase (oil and water) flow model. For the well investigated, sensitivity studies with varying formation properties predict that sand production and cavity generation will be unstable.
Lessons Learned on Gulf of Mexico Gas Wells Drilled With OBM and Completed With Heavy Brine
Authors: McBee Jim , Evans Brian , Umbher Kevin
Published: December 2007

Drilling gas wells with oil-based mud (OBM) or synthetic-based mud (SBM) has been proven to create producing wells with very high completion efficiencies. This property makes OBM use very attractive, even if the reservoir conditions are not the traditional hot, high-pressure, harsh variety usually associated with oil mud usage.

While oil-based or synthetic-based drilling fluids do an excellent job of creating a nonreactive, stable wellbore, they contain additives that can lead to inflow problems if not properly anticipated and treated early in the completion phase. The well can experience drastic or complete resistance to inflow when high-density completion brine, used to control well pressure, is emulsified in situ by OBM filtrate in the flushed zone around the wellbore. Routine post-perforating acid treatments may not have the desired result due to the nature of OBM emulsifiers and wetting agents. Another problem arises when whole mud (oil-or synthetic-based) is lost during drilling and must be addressed before commencing production.

This paper examines two gas well completions in the Gulf of Mexico in which oil-based muds were used for drilling and high-density completion brines were used for post-perforating well control and completion operations. These wells would not flow when opened. Special remedial treatments were required to condition the reservoir, initiate well flow and facilitate drilling, completion and stimulation fluid recovery. The well treatments involved using chemicals to break the downhole emulsion, water-wet the formation and reduce surface tension of aqueous fluids lost to reservoir during drilling and completion. The need for these post-completion treatments has led to changes in well completion procedures to prevent future fluid incompatibilities and formation damage.

Treatment results were notable, with both wells going from zero production to over 7 MMcf/D and an increase in both shut-in and flowing tubing pressures.
Decision Making in the Oil and Gas Industry: From Blissful Ignorance to Uncertainty-Induced Confusion
Authors: Eric Bickel J. , Bratvold Reidar B.
Published: December 2007

The battle against deterministic forecasts and financial valuations in the oil and gas industry appears to have been won, as evidenced by the plethora of papers, conference sessions, and forums focused on uncertainty quantification or profit prediction. Yet, decision makers are still not sure what they should do. Rather than basing important decisions on a single number, they now find themselves buried under a mountain of probability distributions. Uncertainty quantification seems to have confused more than it has enlightened.

In this paper, we present the findings of a survey of oil and gas professionals that addressed the following two questions: To what degree has uncertainty quantification improved in the oil and gas industry over the last five years? Has this improvement translated into improved decision making?

Uncertainty quantification is not an end unto itself; removing or even reducing uncertainty is not the goal. Rather, the objective is to make a good decision, which in many cases requires the assessment of the relevant uncertainties. The oil and gas industry seems to have lost sight of this goal in its good-faith effort to provide decision makers with a richer understanding of the possible outcomes flowing from major decisions. The industry implicitly believes that uncertainty is reduced simply by modeling it and that making good decisions merely requires more information.

To counter this, we present a decision-focused uncertainty quantification framework, which we hope, in combination with our survey results, will aid in the innovation of better decision-making tools and methodologies.
Elevated Activity Levels Driving Technology Development at Record Pace:Barnett Shale-North Texas
Authors: Jennings Drew , Felderhoff Floyd , Isbell Matt , Kramer Mark , Pierce Eddie , Roberts Geoff , Paugh Wesley , Janwadkar Sandeep
Published: December 2007

Increased demand for natural gas and the resulting long-term price stability has caused operators to apply new, high-end technology to accelerate development in the Barnett Shale field of north Texas. Expanding drilling schedules on shortening timelines have resulted in the systematic advancement of technology to keep pace with the increased pressure to cut drilling costs and reduce days to production.

One operator and its service providers recognized the potential to replace established technology and drive down costs drilling horizontal boreholes. A team-based approach focused on discrete well intervals to identify issues, analyze problems, and explore solutions to improve overall performance. In the northern part of the field, the introduction of polycrystalline diamond compact (PDC) bits, modifications to the drillstring, and new operational practices in the vertical hole section, previously dominated by roller cone bits, reduced drilling time by 62% over the interval. To the south, a new approach to critical failure analysis was utilized to double the drilling performance through the lithologically challenging curve section with roller cone bits. The rate of penetration (ROP) and footage advancements achieved in both scenarios have changed the drilling landscape in north Texas and made intense drilling schedules significantly more manageable.

In a six-month period, the 8 3/4-in. vertical section was drilled in just one PDC bit run on 23 out of 30 wells in the northern area, cutting interval costs by $150,000 and drilling time by 62%. To the south, new roller cone technology outperformed 90% of the previous runs, increasing ROP by 84% to 18.8 ft/hr from 10.2 ft/hr, saving the operator a total of $1.68 million over 15 wells.

The paper will outline drilling performance improvements in terms of footage, ROP, and the operating parameters/systems required to achieve the dual performance step change.