bluuebunny/crossref_metadata_2025 huggingface dataset:
Remedial Cementing in Limestone Formation Using Bradenhead Squeeze: A Case History of KS-X22
Authors: Aprilianto E. C.
Published: February 2011

The high porosity of the limestone formation of Kaji-Semoga Field, Indonesia, caused a vast amount of lost circulation during the waterflood drilling campaign. An example of major lost circulation was at KS-X22, which caused a major failure in the primary cementing. This failure resulted in a significant increase in water cut, from 45 % to 96 %, within 6 months.

To make KS-X22 economically viable again, it was decided to improve the primary cement quality by remedial cementing. The job was designed as low-pressure balanced plug placement, with 15.8 ppg G class cement pumped down on open-ended tubing. The limited capacity of the onsite batch mixer restricted the cementing process, which could not be done in one stage. But, to our advantage, this limitation enabled us to control the amount of cement required for the following stage, based on the results of the previous stage.

When the job was finished, the cement bond log showed that it had been done perfectly, indicated by the significant change in the free pipe reading (62 mV) to an excellent cement bond (<20mV). The producing phase after the job showed a slower rate in the water cut increase, and currently the well is still producing using ESP, more than 2 years after the remedial cementing job.

This paper will discuss the planning, implementation, and results of remedial cementing at KS-X22 and the lessons learned
Risk Tolerance and Risk Neutrality (You Can Live With More Risk Than You Think)
Authors: Leach Patrick E.
Published: February 2011

Many exploration and production companies impose a risk threshold on major capital projects (one common such hurdle is a maximum acceptable probability of negative NPV). Projects which fail to meet the threshold are not usually rejected outright; rather, the project team is instructed to gather more information and perform more analyses, so as to reduce the range of economic uncertainty associated with the project. This wastes capital and decreases economic efficiency.

The primary arena in which risk tolerance is applied is the development stage of a project. Companies are comfortable with the notion of failed exploration wells, but not failed developments. Stringent probability-of-success hurdles often result. Unless the failure of a single project could put a firm into financial distress, companies should be risk-neutral when making decisions at the project level – i.e., they should make project optimization decisions based on the mean values of the economic metrics of interest (NPV, P/I, etc.) with no further consideration taken of the probability of success. Value-of-information (VOI) analyses should be used to determine when additional information or analysis adds value to a project and when it does not. Risk tolerance should be applied at the portfolio level, not the project level. The question to ask is not, "Am I comfortable with the risk associated with this project?"; rather, it is, "Am I comfortable with the risk associated with my portfolio of projects when this project is included?"

Projects are routinely delayed while unnecessary appraisal wells are drilled and analyses are conducted, thus eroding millions of dollars from the NPV of these projects. Correcting this issue will require a change in the way many project managers are evaluated and compensated, but the potential benefit to the companies – and the industry – is huge.
Prediction of Uncertainty in Exploration of Unconventional Gas Reservoirs
Authors: Kelkar Mohan , Bonney Kyle , Bonney Phillip
Published: February 2011

Once a new unconventional play is identified, companies would start acquiring sizable land holdings within the same play. Before acquiring, the companies would like to answer several questions: how much to pay for the bonus; what is the strategy to initiate the drilling program and how to determine the uncertainty related to EUR from these wells. Most companies would use the data from existing wells within the same play or similar play to estimate what type of production to be expected from the land to be acquired. Based on the results, they will determine the bonus as well as expected uncertainties.

We approach this problem using a novel method. We use the analog EUR data to develop the spatial relationships for the analog field. By assuming log-normal distribution for EUR data, we build the equations for the EUR for the new area. Appropriate scaling considerations can be included in these equations. For example, the newly acquired area may have smaller thickness than the analog or would use longer horizontal wells. We generate a graph of p10, p50 and p90 EUR values for the initial drilling program, starting with the first well. Knowing the uncertainty in EUR values, the initial bonus, based on appropriate economic criteria, can be determined. Once the land is acquired, as the initial drilling program is initiated, the method will allow the company to compare the performance of actual well with the expected uncertainty range. Depending on the locations of the wells and spatial relationship, the uncertainty will change differently. By using the method, the company can evaluate if the average performance of the drilled wells is within the realm of acceptable uncertainties or should the model be changed based on the new data available. We validated the proposed method for a shale play in Oklahoma.
Coalbed Methane Production: Why Coal Permeability Matters
Authors: Chen Dong , Liu Jishan , Pan Zhejun , Connell Luke D.
Published: February 2011

When coalbed methane is recovered, complex interactions of stress and chemistry have a strong influence on the properties of the coal. These include influences on gas desorption and flow, coal deformation, porosity change and permeability modification. Although coal-gas interactions have been comprehensively investigated, all of these prior studies usually assume that these interactions are under conditions of invariant total stress where effective stresses scale inversely with applied pore pressures.

Here we develop a novel coal permeability model that defines the relations between directional permeabilities and strains, and implement a FE model that couples desorption of the coalbed methane and water flow within a deformable medium (coal) where the effects of deformation are rigorously accommodated. This relaxes the prior assumption that total stresses remain constant and allows exploration of the coalbed methane production under the full range of mechanical boundary conditions from invariant stress to restrained displacement.

We apply this model to investigate the productivity of coalbed methane production under in situ conditions. The results show that increasing the absolute permeability could shorten the dewatering stage of the coalbed methane production, but the shape of the production curves does not change with the absolute permeability. For permeability anisotropy coal seams, the fluids mainly flow in face cleats direction and locating more wells in butt cleats direction is high efficient for coalbed methane production. The relative permeability dominates the fractional flow and thus controls the shape of the production curves. It determines when the commercial gas rate could be achieved and how much water should be coped with during the dewatering stage. Therefore both the absolute permeability and relative permeability are key factors for the dewatering stage of the coalbed methane production.
Horizontal Well Optimization With Inflow Control Devices (ICDs) Application in Heterogeneous and Dipping Gas-Capped Oil Reservoirs
Authors: Rahimah A. K. , Azrul N. M. , GordonGoh K. F. , Asyikin A. N. , Leung E. , Johan M.
Published: February 2011

SS field is located offshore East Malaysia. 2 exploration wells discovered multiple dipping reservoirs, with oil column of about 40 m. The heterogeneous reservoirs, combined with a very large gas cap (i.e. m size of 2) and moderate aquifer strength impose challenges to maximize recovery from this field. Field development study has formulated 14 horizontal wells with 3 water injectors to achieve recovery factor of 30%. Optimum reservoir management strategy requires a delicate balance of gas cap expansion and water injection drive, where the optimum voidage replacement ratio is only 0.25. However, reservoir dynamic modelling shows that all the wells will get early gas and water breakthrough. ICD technology is therefore evaluated to address the above production and recovery dilemma while prolonging the production life.

In this paper, optimization of 12 horizontal ICD wells out of 14 wells will be discussed. This includes the process of qualifying and designing the ICD application in each candidate through static modelling. Full field dynamic modelling was also conducted to quantify the real benefits of ICD, and confirming the robustness of the design throughout field life. In view of high uncertainty of fluid contacts and reservoir quality in unappraised areas, the team has adopted the unique yet challenging approach of field appraisal from pilot holes during the initial implementation stage. This has provided valuable data prior to horizontal drilling and final optimization of ICD. Subsequently, the production performance from the first ICD wells will also be discussed to provide evidence on its effectiveness and lessons learned.

Finally, the paper highlights the importance of seamless teamwork and coordination between project team and service providers to deliver superior performance. This can be an informative workflow source for future applicants of such technology with similar fields’ nature and risks.
Nonchemical Bacteria-Control Process
Authors: Neal Greg , Kleinwolterink Kembe , Abney Laurence , Gloe Lindsey
Published: February 2011

This paper describes a proven method to control bacteria growth in pipeline and process service fluids using irradiation technology. Service fluids are exposed to an irradiation source that disinfects the fluids and eliminates the need for biocide chemistry. The disinfection process can be used as a standalone process or in conjunction with traditional chemical treatments for many oilfield service applications.

The commissioning process for pipelines typically requires hydrostatic-pressure testing. The test fluid is usually treated for potential bacteria accumulation. Using the nonchemical process of irradiation to disinfect the test fluid eliminates the need for hundreds of gallons of bactericide. The service greatly reduces employee exposure to hazard-rated biocides and associated health- and safety-related issues, significantly improving overall environmental aspects of the operation.

Bacteria play an important, although usually detrimental, role in the production and transportation of hydrocarbons. The slime- forming version of bacteria can corrode surface piping and storage facilities. In addition, bacteria have been known to restrict reservoir porosity with "bio-plugging" or "bio-fouling." One anaerobic form of bacteria is sulfate reducing bacteria (SRB), which reduces the sulfate ion to sulfide. This can lead to the corrosion of flow-wetted metal components and to the formation of hydrogen sulfide (H2S) gas, which is extremely hazardous to humans and other animals. Fluids containing H2S can be damaging to production facilities not specifically designed to be H2S resistant.

The nonchemical alternative to biocide has cost and environmental advantages over traditional chemical treatments.
A New Approach to Flowline Active Heating
Authors: Abney Laurence
Published: February 2011

The industry drive to develop marginal fields, heavy oil, or increased oil-recovery options from new or existing fields requires that the design of system components be examined and questioned. Extended-reach (cold water) flowlines that transport unprocessed fluids from the wellbore through to a receiving or processing facility require effective insulation systems or an active heating system to assure the integrity of the fluids in the line. Additionally, to meet flow-assurance requirements, production chemistry is used at the inlet of a flowline to prevent the formation of hydrates and to manage paraffin wax or scale formation. The production chemicals are usually injected through chemical-transportation facilities in an electrical/hydraulic-control umbilical that is laid parallel to the flowline.

Flowline active-heating systems and high-performance insulation systems add significantly to the capital cost of a project; additionally, the design and fabrication of control umbilicals that include multiple chemical-injection conduits increase the capital required to develop a field.

This paper presents a new concept in flowline active-heating and chemical-injection systems that will reduce the capital cost of flowline and umbilical infrastructure while enabling significant flexibility in the application of production chemistry. The system challenges of existing flowline design, umbilical design, and the philosophies of field operational maintenance/pigging are reviewed.
Sand Production Prediction for a Mature Oil Field Offshore East Malaysia - A Case Study
Authors: Wu B. , Bahri C. , Tan C. P. , Li Q. , Rahim H. , Kartoatmodjo G. , Friedel T.
Published: February 2011

As an oil field depletes, stress and pressure change in the reservoir. Water and gas breakthrough are also expected to occur. These increase sand production propensity, limit production rates and bring forward the abandonment of the field. This paper presents a sand production case study for a mature oil field offshore Malaysia. The field has been on production for more than 20 years, and an infill drilling program was recently initiated. Sand production risk for the planned horizontal wells in this mature field was a concern for the program. The objective of the study reported in this paper was to quantify sanding risks and recommend sandface completion options for the planned horizontal wells.

An integrated workflow was applied to the study, encompassing mechanical earth modeling, sand production model development and validation, and prediction of sand production propensity for the planned wells. Relevant wireline logs were utilized to derive formation mechanical properties which were calibrated with laboratory-measured values. Leakoff tests and borehole breakout information were utilized to constrain horizontal stress magnitudes. Sand production model was developed and validated based on sand production experienced in the field to date. Sand production risks were assessed for the planned horizontal wells with various completion options. Sand production propensity, presented as critical drawdown pressure was established for all the reservoir formations. It was concluded that sand production risks exist for most of the completion scenarios studied, and downhole sand control would be needed. The study provides a solid basis to optimize sandface completion for the planned wells.
Methods for Enhancing Far-field Complexity in Fracturing Operations
Authors: East Loyd , Soliman M. Y. , Augustine Jody
Published: February 2011

For decades the oil industry has struggled to overcome near-wellbore fracture complexity during fracturing treatments, particularly in low-permeability, naturally fractured hard-rock reservoirs. A number of techniques have been created to diagnose and remediate these conditions to enable extension of created fractures and successful placement of proppant deep in the reservoir. Microseismic fracture-mapping (MSFM) technology has revealed the creation of far-field complex fracture networks in hard-rock reservoirs during fracture extension. This revelation offers the opportunity to hydraulically connect to a much larger volume of rock, provided appropriate treatment techniques are applied to ensure the fracture network is adequately connected to the main fracture. Additionally, techniques have been developed and can be applied during the fracture treatments to facilitate and enhance the fracture-network creation. Net fracture-extension pressure analysis combined with real-time MSFM allows for identifying the degree of fracturing-network creation and provides a decision-making tool for engineers to modify treatment schedules or apply complexity-enhancing methods on-the-fly based on desired treatment objectives and rock responses to the fracture treatment.

This new approach to fracture stimulation requires a new focus on rock mechanics that includes defining the brittleness of the rock matrix, determining the existence and magnitude of the principal-stress anisotropy, designing the optimum spacing between fractures, and defining the optimum fracture-treatment parameters. Once the completion design is implemented, the designed treatment parameters can be adjusted real-time to meet the objectives of the completion based on actual rock responses to the treatment. These rock responses are measured in real-time using net fracture-extension pressure and MSFM diagnostics. Adjustments made to the fracture treatment are varied and include treatment-rate adjustments, proppant concentration, proppant- slug placement, reservoir-diversion treatments, viscous fluid spacers, acid spacers, and incremental stop-start pumping schedules. The proppant-concentration adjustments are enabled for immediate downhole changes through a unique coiled-tubing (CT) fracturing process that incorporates liquid-sand concentrate slurries.

Examples of actual completion designs of these applications are discussed.
Sensitivity of a High-Resolution Fluid-Density Sensor in Multiphase Flow
Authors: Gao Li , van Zuilekom Tony , Pelletier Mickey , Proett Mark , Eyuboglu Sami , Engelman Bob , Elshahawi Hani , Hows Melton
Published: February 2011

An important objective of wireline formation testing is the accurate determination of in-situ fluid properties, including density. However, sensors are frequently subjected to multiphase flow when sampling, which can lead to inaccurate determination of the fluid properties and ambiguity in sample contamination analysis. In this paper, we study the behavior of multiphase flow using a density sensor and the implications for the determination of in-situ fluid properties and sample contamination, together with other downhole sensors.

A vibrating-tube density sensor operates under the physical premise that its resonance frequency is directly related to the density of fluid within the tube. In reality, however, because of its high sensitivity, the sensor response is influenced by multiple factors, including sensor temperature, pressure, and specific mechanical design configuration. A theoretical study of the physics of a vibrating tube density sensor was performed using a first principle-based approach to optimize sensor characterization and accuracy. By considering all forces acting on the sensor under downhole conditions, a comprehensive theoretical model was established for the vibrating density sensor. This theoretical model is validated using experimental measurements in which we contrast theoretically predicted sensor responses with laboratory-measured responses. We compare these results with log examples using downhole fluid sample results and densities. This paper includes the conclusions derived about the accuracy of measuring fluid densities with this new sensor and a comparison of this measurement with traditional data sources.
Synthesis and Properties of Petroleum Sulfonates for Weak Alkali ASP/Alkali-free SP Combination Flooding
Authors: Youyi Zhu , Qingfeng Hou , Hong Yuan , Zhe Wang , Jie Wu
Published: February 2011

Field tests of ASP chemical combination flooding show that chemical combination flooding can greatly increase oil recovery for high water cut oilfields in China. The major problem in ASP flooding technique is that in the strong alkali ASP system, scaling and emulsification bring problems in lifting and produced liquid treatment. In order to avoid the side effect caused by using strong alkali, the development tendency of chemical combination flooding changes from strong alkali ASP flooding to weak alkali ASP flooding and to alkali-free SP combination flooding. The key problem in the weak alkali ASP flooding/SP flooding technique is to develop the surfactant with high interfacial performance, good oil displacement efficiency and lower cost. In this paper, the petroleum sulfonate was synthesized by using Ketone-benzol deep-dewaxing oil fraction as feedstock which with high aromatic content, screening the oil fractions by control average molecular weight of feedstock. The High viscosity stocks were sulfonated using short column falling film reactor. The active content of the petroleum sulfonates synthesized are higher than 38% by direct sulfonating process, it did not require further purification, and thus the synthetic process was improved and the cost was decreased. IFT property of the petroleum sulfonates synthesized showed that ultralow interfacial tension (10−3mN/m) can be reached for Daqing oil/formation water (weak alkali ASP system) and for Jilin oil/formation water (alkali-free SP system). Laboratory core oil-displacement of ASP/SP combination flooding showed that the oil displacement efficiencies of ASP/SP flooding with these surfactants can reach 62-65%(OOIP) which was about 20% and 18% respectively higher than that of the conventional water flooding.
Horizontal Wells with Multi-Stage Fracs Provide Better Economics for Many Lower Permeability Reservoirs
Authors: McDaniel B. W.
Published: February 2011

During the past 5+ years, North America operators have increasingly turned to horizontal completions in low permeability oil and gas reservoirs to maximize their Return on Investment (ROI). As hydrocarbon prices suffered a freefall in late 2008 to mid-2009, this further forced operators to continually evaluate both cost and effectiveness of various completion and stimulation options. In April 2008 the Baker Hughes U.S. rig count for vertical drilling was twice the horizontal rig count, but after the price collapse we soon had more horizontal rigs running than vertical ones, with the June 2010 ratio being ∼1.7:1 while only four years ago the U.S. had 2.5 vertical rigs for every horizontal rig.

Globally, the trend toward horizontal drilling of low permeability oil and gas reservoirs is slowly increasing, with some of the lower permeability onshore and offshore fields also following this trend. As operators see many of their current horizontal completions in moderate to low permeability reservoirs reach their economic limit in only a few years, they often would like to use hydraulic fracturing. However, they are realizing the frac limitations imposed by openhole completion methods and even for highly perforated cemented laterals. Only a few viable options currently exist for effectively placing individual hydraulic fractures at (and ONLY at) preselected locations along the completed lateral section. Unfortunately, often the existing completions limit the fracturing rates that can be achieved.

The primary focus of the North America model for horizontal well economic success is completions that enhance the ability toachieve both adequate injection rates and effective isolation of hydraulic fracturing stimulation stages. In some fields, a secondary goal is to drain significantly more reservoir per well by using radical lateral lengths and reduce the number of wells needed. Onshore this concept makes each well much more environmentally friendly, and offshore the economic value is even more obvious.

This paper will provide a high-points review of the shale formation completion model. With this model it is critical to select the multi-stage fracturing implementation to be used before the lateral completion method can be chosen. Many current methods require that the installed lateral completion contain specific components that are a part of the stimulation isolation method itself. Also reviewed are a few areas that could further advance the present methodology and offer suggestions for where the industry can consider non-shale applications to further proliferate this methodology outside North America.
Permanent Abandonment of a North Sea Well Using Unconsolidated Well Plugging Material
Authors: Saasen Arild , Wold Sturla , Ribesen Bjørn Thore , Tran Tu Nhat , Huse Arve , Rygg Vidar , Grannes Ingvar , Svindland Alf
Published: February 2011

The traditional Plug and Abandonment (P&A) method of exploration wells in the North Sea is to set a series of cement plugs to isolate the pressurised zones from each other and from surface. This paper describes a North Sea P&A field case. In this case an alternative method with a Bingham-plastic unconsolidated plugging material with high solids concentrations was used. This alternative method addresses well integrity issues like those caused by shrinking of cement or gas migration during setting, fracturing after setting, or long term degradation by exposure to temperature and chemical substances in the well.

The gas tight Well Barrier Element (WBE) described here does not set up after placement and does not shrink. Furthermore it cannot fracture even when shear forces exceed its strength. When this happens the material floats and shear forces are reduced below yield strength causing the plug to reshape. Since this is a purely mechanical process the transition between solid and fluid phase is repeatedly reversible forever.

The plug is thermo-dynamically stable since its sealing property is decided by the solids particle size distribution and bound water only. The closely packed particles and absence of free water means that the entire column is kept homogenous and no internal re-distribution of particles may occur. Hence, the permanent gas-tight barrier will prevent influx through the well bore forever.

In the field case a successful implementation of the technology was obtained. The field case shows how the fast and efficient placement of the plug contributes to overall cost reduction. The paper explains how the well barrier element complies with governmental permanent P&A requirements and the operational procedures are also presented in some detail.
Innovative Metallurgical Technology Delivers First Sulfide Stress Cracking Resistant Intervention Riser System with Quick Running, Rugged Connections
Authors: Jellison Michael , Hehn Lucien , Moreira Jose Roberto , Joia Carlos J.B.M. , Wyble Kevin , Christen Brian
Published: February 2011

Petrobras has been using a 6-5/8 in. drillpipe based riser system for intervention work offshore Brazil for several years. The primary advantage of the drillpipe based system relates to the rotary shoulder connections (RSC). RSC’s make-up and break-out quickly, are rugged and are superior at resisting galling and other handling damage compared to OCTG connections that are often used for riser applications.

Petrobras has been prevented from expanding their use of the intervention risers in sour gas areas because there were no fully Sulfide Stress Cracking (SSC) resistant tubulars with RSC’s. The intervention riser configuration consists of upset to grade tubes friction welded to tool joints that are typically constructed from forgings. Sour service drillpipe has been available for some time. This pipe is built with SSC resistant upset tubes and tool joints. The friction welds joining the upset tubes and tool joints were not resistant to SSC. This is acceptable for drilling since the weld is not the high stress area of the assembly and the drilling environment can be controlled through the drilling fluid properties and additives. Petrobras’ critical sour riser applications could entail direct and prolonged exposure to H2S gas. Consequently, a fully SSC resistant system including the friction weld was required.

This paper presents the successful development and qualification of SSC resistant friction welds for intervention riser systems. It describes the engineering and manufacturing philosophy employed, laboratory testing procedures and results and Petrobras’ applications for the new risers. Since NACE MR-0175 does not address friction welds the engineering team developed unique and innovative criteria and testing procedures for the new weld technology. A new patent pending four point bending test procedure and fixture were develop that employed unpolished samples that closely represent the finished product surface finish (NACE testing typically uses polished specimens).
Pressure Transient Analysis and Simulation of Nonconventional Wells
Authors: Iktissanov V.A.
Published: February 2011

Nowadays nonconventional wells (horizontal, multilateral, Rad Tech and others) are being extensively drilled throughout the world for the development of low-profit fields. Construction of these wells enables to reduce filtration resistivity resulting in productivity index increase and costs reduction.

To select the optimal well design with regard to reservoir characteristics, effective well operation and determination of filtration characteristics one should possess calculation methods for steady and unsteady liquid flow in reservoir.

Few related papers have been published so far. However analytical methods for steady flowing are suitable for homogeneous beds with simple geometry and equal length laterals. Available approaches for description of pressure build up allow to account for various lateral trajectories but FEA or semi-analytical decisions methods are too labor-intensive for practical application.

Therefore simple methods of productivity index determination and pressure transient test interpretation are suggested for nonconventional wells. These methods are suitable for low thickness beds. The basis of these methods is the superposition of filtration resistivity for two plane problems. Trajectory of laterals is simulated as a number of closely spaced vertical wells or nodes. The suggested method allows determining the field of application and regularities for nonconventional wells.

Dimensionless fluid-movement profile calculated from steady fluid flow and a superposition method for pressure builds up in the nodes are used for determination of pressure build up. For description of build up in a node we recommend a diffusion equation in Laplace space and Stephest numerical algorithm. The problem is solved for porous and doublt porosity reservoirs.

Numerical calculations show that cross-flows occur after the horizontal or multilateral well shut-down. Pressure derivative maximum testifies to low effective length of the borehole or positive skin-effect. Knowledge of effective intervals length is critical to pressure curve interpretation.
Production Logging in Highly Deviated and Horizontal Wells: Moving From Qualitative to Quantitative Answers
Authors: Gysen Alain , Gysen Michel , Zett Adrian , Webster Mike , Yusti German
Published: February 2011

A variety of technologies have been used to address the challenges faced by Production Logging (PL) in high deviation and horizontal wells.

Different configurations of array sensors have been deployed in these environments, to address well work objectives. There are situations where it is hard to differentiate between qualitative and quantitative answers. The question is how quantitative is high angle and horizontal PL data.

Multiple datasets were studied and increased value can be added to array raw data by improvements to processing and interpretation. There is a need to differentiate between data acquisition and data processing and interpretation for high angle and horizontal PL.

This paper describes a probabilistic approach developed to combine sensor responses into a quantitative solution. Individual sensors from a multiple array production suite can be used in combination with centralised (conventional) sensors to address reservoir conditions and well access challenges. Difficult well completion and rig height limitation increase the complexity level in such environments. This probabilistic approach is applied in a complex North Sea example to gain greater reservoir understanding with a rapid turnaround.
Sourceless Porosity Estimation in Gas Reservoirs Using Integrated Acoustic and NMR Logs
Authors: Lan Chun , Chen Songhua , Mendez Freddy , Sy Rex
Published: February 2011

Due to environmental concerns, the use of radioactive chemical sources is discouraged. This presents great challenges for conventional practices. Source-free logging tools, such as Nuclear Magnetic Resonance (NMR) and acoustic tools, have also been used for porosity determination. However, sometimes uncertainties in lithology, mineralogy, and/or fluid properties can result in unacceptably large error bars in porosity by either NMR or acoustic logging alone. Integrating acoustic and NMR measurements for gas-zone porosity estimation has been reported in relatively clean sandstones. The existing method in literature has not been extended to shaly sandstone reservoirs or carbonate formations where clay is also present. We developed a new, practical sourceless porosity-estimation method which uses NMR log to calibrate the acoustic porosity model and which corrects shale effect on acoustic porosity.

To apply this method, both clean and shaly water-bearing intervals are selected for calibrating acoustic model parameters. By applying the calibrated model, dry matrix slowness on each depth in the gas-bearing interval can be obtained. Porosity can then be determined by introducing the computed dry matrix slowness to Raymer-Hunt-Gardner transform for the gas-bearing interval.

This method has been successfully tested on a number of wireline and LWD logs. In this paper are two case histories; one case study involves a shaly sand reservoir, and the other, a low-porosity carbonate reservoir. For both cases, the sourceless porosity is cross-validated with other approaches for both the water-bearing and gas-bearing sections.
An Alternative Mechanistic Model for Permeability Changes of Coalbeds During Primary Recovery of Methane
Authors: Mazumder Saikat , Farajzadeh Rouhi
Published: February 2011

Volumetric shrinkage due to methane desorption from the coal matrix has significant influence on the stress regime and fracture permeability in coal. Permeability changes (due to primamry depletion) up to two orders of magnitude have been reported from the Fairway region in the San Juan Basin. Several analytical models have been developed to predict changes in fracture permeability in coal as a function of stress and sorption induced coal swelling/shrinkage.

Coal can be considered as a highly crosslinked macromolecular network structure, where aromatic clusters of graphite like complexes are connected by aliphatic chains. All sorption processes in coal are characterized by relaxational mechanisms of such crosslinked complexes. Any relaxational mechanism is indicative of swelling related stresses in coal. Variations in the effective horizontal stresses under uniaxial strain conditions are effected as a function of the reservoir pressure reduction during primary drawdown, which includes a cleat compression term and a matrix shrinkage/swelling term that have opposite effects on fracture permeability.

The matrix shrinkage/swelling term have been revisited a theory proposed to explain the coupling of swelling stress to porosity change in coal as a function of the change in diffusion coefficient, the Langmuir constants, cleat compressibility and material properties.
30 Years of Successful High-Pressure Air Injection: Performance Evaluation of Buffalo Field, South Dakota
Authors: Kumar V. K. , Gutiérrez D. , Thies B. P. , Cantrell C.
Published: February 2011

The Buffalo Field enhanced oil recovery project is the oldest, still active, air injection project in the United States. The combination of depth (8,500 ft), high pressure (4,200 psi), light oil (32 °API), high reservoir temperature (215 °F) and low permeability (1 to 20 md) carbonate formation makes this a unique air injection project, covering a large area (33,160 acres). The project's longevity attests to both its technical & economic success.

Laboratory studies (combustion tube, miscibility pressure and swelling tests for various CO2-N2 mixtures) and feasibility studies including air injectivity testing were completed in mid-1977. The result of the pilot test was promising and the 2,240-acre Buffalo Red River Unit (BRRU) was formed in November 1978. As production response continued to be encouraging, the BRRU was expanded to 7,680 acres in May 1981. Two other EOR units, South Buffalo Red River Unit (20,800 acres) and West Buffalo Red River Unit (4,680 acres) were formed adjacent to BRRU, in 1983 and 1987 respectively.

The three units currently have a total of 59 producers and 20 injectors. Oil production in all units has shown significant increase over its historical decline under continued primary. Peak production reached 3,030 BOPD in June 1991. Current production is 1,500 BOPD and injection is 30,500 Mcfd. Cumulative air injection through December 2009 is 262 Bcf and the incremental production due to air injection is about 18.1 Million barrels resulting in cumulative air utility of 14.5 Mcf/incremental barrel.

This paper focuses on the technical aspects of the Buffalo EOR project, reviewing laboratory studies, production performance (1978 to 2009) and the impact of short radius horizontal drilling. It also includes estimates of the EOR barrels produced, how air utility and air retention have changed over time, and estimates of the burned volume in each of the units.
Modern Marine Transport of Compressed Natural Gas in 2010
Authors: Wang Xiuli , Economides Michael J.
Published: February 2011

Worldwide natural gas is transported with two well-established technologies: 70 percent by pipeline and 30 percent by liquefied natural gas (LNG). For offshore transportation, pipelines have a distance limit and terrain restrictions. LNG is applicable for long-haul sea distances and large gas volumes, because the facilities at both ends are expensive to construct and the entire process is complicated, costly, and energy wasteful.

We and others have proposed that compressed natural gas (CNG) transportation by boat is an alternative for shorter distances and smaller markets that are not connected to large pipelines or base load LNG accepting facilities. Although this approach has been proposed for years, it has not yet materialized into a sizeable project. The industrial emphasis on LNG has affected CNG projects and one of the reasons is that some proponents have attempted to take some market share from LNG. This is not a viable approach.

In this paper, results show that for shorter distances (e.g., 1,000 km) and especially for the far lower natural gas prices that have emerged since the 2008 economic crisis, LNG simply cannot compete with CNG. Even at longer distances (e.g., 2,000 km) CNG is still more attractive, assuming that offshore pipelines are not feasible. For smaller volumes, such as 1 to 2 billion cubic meters per year (Bcm/yr) or even less, CNG is the only solution to bring this energy source to many markets. In other words, smaller and smaller markets are ideal for CNG.

The preferred path for CNG transportation vessels may follow what we have called in earlier publications "hub -and-spoke" or cyclical "milk-run" patterns depending on market demands at the receiving sites.

These findings suggest that many parts of the world (many markets in the entire Mediterranean basin, near Sakhalin Island, places in South-East Asia and the Caribbean) would be better served by CNG even if LNG projects have already been approved and under construction near them.
Uncertainty Management: A Structured Approach Towards Recognizing, Quantifying and Managing Subsurface Unknowns
Authors: Alessio Laurent , Everts Arnout , Rahmat Faeez
Published: February 2011

This paper illustrates, through field studies examples, why and how a structured approach towards managing uncertainties, and especially sampling biases, delivers valuable insights through the successive early asset life stages - exploration, appraisal and field development phases. In doing so, we respond to three fundamental questions.

Firstly, ‘What are the key uncertainties – those that matter?’ Field studies should begin with a comprehensive upfront assessment of uncertainties’ impact on historical and future well and field performance. However, often major factors are overlooked, leading to under-prediction of true outcome ranges and the inability to reconcile historical production. Our illustration is a large producing carbonate field, where after 15 years of production, large scale Karstification was finally evidenced to be the explanation for the field performance that couldn't be history matched with the measured matrix porosity and permeability ranges.

Secondly ‘What are realistic ranges for these uncertainties?’ Known Industry best practices include intensive expert-assist, integration of drilling, mud-logging and other traditional sources of data from the field, resorting to analogue benchmarking. Despite these, we often fail to understand and correct for sampling bias, which we show often leads to over-optimism. The paper will highlight why such biases are present and propose simple and practical methods to remove them. The case study is the volumetric assessment of a gas discoveries portfolio, where geophysical techniques were instrumental in exploration and appraisal drilling.

Finally ‘How these uncertainties will evolve with time?’ This is an important question for assessing value of Information: the impact that additional data may have on the uncertainty range of uncertainties and the base case. Unconventional fractured plays, often characterized by data abundance but extreme variability, provide surprising insights on how uncertainties ranges evolve. This paper presents methods to develop confidence curves for important parameters.
Multi-Circulation Steam Generator Concept
Authors: Corriger E. , Abry G.
Published: February 2011

To "push" water impurities toward the tail of your Steam Generator where exchanged heat flux is low, this is the main purpose of the Multi-Circulation concept.

This is done by design with Once Trough Steam Generator (OTSG) while for water tubes drum boilers (WTD) impurities concentration in boiler water remains constant from boiler entrance (furnace side, with high heat flux and high flue gases temperature) to boiler tail (exit side with low heat flux and low flue gases temperature). Refer also to Fig 1

Both of these boilers are water tubes type: water & steam side is tubes side.

One other main specificity of OTSG boiler is also that water volume ratio decreases from 100 % at tube entrance (furnace side typically) down to 2 or 3 % -typical for 100 bar pressure - at tube exit (boiler exit typically) (Refer also to Fig 2); so such boilers can be subject to inside tubes fouling when salinity is too high and / or blow down rate is too low. You have to make arbitration between maintenance costs and water & energy costs varying in opposite way by selecting the right boiler blow down rate. Boiler yearly availability is also a consequence of this decision.

For WTD boilers, water volume ratio is quite constant from entrance to exit as for this kind of boiler, natural circulation is controlled by design; operator has no impact on this parameter for a boiler operated within it normal design range. These boilers are then less subject to tubes fouling but water characteristics are more stringent. Of course boiler tubes fouling are mainly depending on feed water quality - so on water treatment system - and on boiler characteristics such as water volume ratio, heat flux and salinity level. When salinity concentration increases and when water volume ratio is low, fouling risks by deposits are then max. With some salts such as Silica having a low thermal conductivity, even very thin deposits have a great impact on tubes wall temperature leading quickly to tubes failures if they are in hot flue gases (furnace side).

Regarding these parameters each boiler type is different and then boiler shall be selected carefully considering advantages and inconvenient of each type.

Then, if you have to operate your boiler with low quality feed water and high availability rate we would recommend you prior to select one of two well know boiler type - OTSG or WTD - to consider a third type: the MultiCirculation Steam Generator (MCSG).

The Multicirculation, what is that? A kind of OTSG / WTD hybrid: a WTD design slightly modified to include one OTSG main characteristic: variable boiler water salinity from inlet to outlet. Then this MCSG boiler has advantages of both types: Low Feed water quality, low blow down rate, high water volume ratio and then and Low Fouling risks. (Refer also to table 1).

Heating surfaces of a MCSG boiler are then subject to or highest heating flux and lowest water salinity, or lowest heating flux and highest water salinity, but never to highest flux and highest water salinity.
Inducing Spherical Flow Conditions with Formation Testers
Authors: Betancourt Soraya S. , Dussan V. E. B. , Lake Larry W.
Published: February 2011

Permeability is one of the most important parameters for evaluating the production potential of a reservoir. Though there are several ways to determine permeability, the focus here is on formation tester pretests. The pretest is a routine measurement that provides in situ values of formation mobility (permeability/viscosity) at several depths along a wellbore. Because this measurement is easily accessible, it is of interest to maximize the value of the information obtained.

Two types of mobility can be determined from a pretest, one of them is the mobility obtained using the amplitude of the pressure signal, usually referred to as drawdown mobility. This measurement has a very shallow depth of investigation; therefore, it characterizes only the formation in the immediate vicinity of the probe, i.e., it is an indicator of the mobility at the wellbore wall, where formation damage is likely to occur. The uncertainty associated with this mobility measurement decreases when the drawdown is long enough to approximate steady state flow. Another way of inferring mobility is done by analyzing the pressure transient signal during the late stage of buildup, during the so-called spherical flow period, hence it is referred to as the spherical mobility. This method has the advantage of characterizing properties deeper in the formation. However, the spherical flow regime is usually difficult to identify in the recorded pressure signal, and in the few instances where it has been claimed to be identified, the inferred formation mobility is almost always smaller than the drawdown mobility. A major problem in analyzing pressure data during the spherical flow period is that it requires quantifying a small rate of change in the signal as equilibrium is approached.

In this study, we model the performance of three different tool configurations with six different formations having mobility ranging from 0.001md/cp to 100md/cp, to identify the pretest parameters that maximize the pressure signal during the spherical flow regime. The results may be used as a general guideline on the selection of pretest parameters when the objective is to evaluate formation properties away from the wellbore. When representative values of drawdown and spherical mobility are obtained, it is possible to infer the undamaged formation mobility as well as the magnitude of the formation skin.