bluuebunny/crossref_metadata_2025 huggingface dataset:
Insertable PC Pumps Reduce Operation Costs
Authors: Martinez Miguel Angel , Lopez K. Jorge Mario
Published: December 2007

With the main objective of reducing working times of rig equipments and this way costs for operator companies an insertable Progress Cavity Pump (PCP) has been developed. This pump is designed to be anchored in the top (by cups) and with a 2 7/8" anchor in the bottom section.

This kind of pumps can be installed in wells where beam pumped systems were installed before, and vice versa, avoiding the production string pulling. So if a change from a beam pumped system to PCP system is required, utilizing this new design, the rig activity would be limited to: pulling rod string, changing the pump and installing the string again. If a fast mounting rig is used to realize the replacement, the working time could be shorter.

Other advantage of insertable PCP is that the production flow rates has been increased, obtaining a several range of applications.

This paper presents a short technical description of and some tests of insertable PC Pumps in different wells of Guadales and Lomas Del Cuy oilfields (Area Guadal – Las Heras – Repsol YPF). Theses pumps were tried at different depths, stresses, hydraulic powers and other well conditions in order to demonstrate the same performance of traditional PC Pumps.

An economical analysis exhibits the convenience and some qualitative benefits of installing insertable PC Pumps in a certain range of wells, depending on their flow rates, especially when a beam pumped system will be replaced for a PC Pumped system. Besides it provides a future projection of insertable PC Pumps installations in the mentioned oilfields.
A Composite Determination of Mechanical Rock Properties for Stimulation Design (What To Do When You Don't Have a Sonic Log)
Authors: Mullen Mike , Roundtree Russel , Barree Bob
Published: December 2007

In the Rocky Mountain region of the US, nearly every well is hydraulic fracture stimulated to produce commercial volumes of oil and gas. The starting point for designing these treatments is an understanding of the in-situ stress profile. To calculate the in-situ stress profile, one must have an understanding of the mechanical rock properties and the pore pressure variations throughout the wellbore. Pore pressure can be measured in the permeable zones and in-situ stress can be calculated by the modeling of closure stress from pre-fracture pressure testing. But these tests are rarely performed in the nonreservoir rocks above and below the fracture stimulation treatment. The challenge for the stimulation design engineer is to determine the mechanical rock properties in and around the treatment interval. Calculating in-situ stress with the uniaxial strain equation requires the knowledge of Poisson's ratio, Young's modulus, pore pressure, and overburden pressure. Classically, the static Poisson's ratio (PR) and Young's modulus (YMS) are calculated by using the results from a dipole sonic log. However, in most fields, less than 1% of the wells requiring stimulation have dipole sonic data.

In the absence of dipole sonic information, conventional wireline log data can be used to quite effectively calculate mechanical rock properties by using basic petrophysical relationships and artificial neural networks. The composite method to determine mechanical rock properties uses five methods to estimate the compressional slowness (DTC), seven methods to estimate shear slowness (DTS), eight methods to estimate PR, and and nine methods to determine YMS. The composite model PR and YMS are error minimized by a weighted averaging technique that honors the most reliable correlations. The composite modeled PR and YMS values are then used as inputs for a continuous calculation of the minimum horizontal stress (Shmin).

The validation of the new composite model PR and YMS was confirmed in three ways. First, the composite model results are compared to the values determined in the lab from actual core samples. Second, the composite model results were compared to calculations using measured DTC and DTS in wells where dipole sonic tool measurements were recorded across a field in Wyoming. Finally, the composite model results were validated by using stimulation treatment pressure history matches on the Pinedale anticline in southwestern Wyoming. The goal of the composite model is to provide a robust rock property solution with or without sonic log data to eliminate the mechanical rock properties as a variable in fracture stimulation treatment design and history matching.
Olefin Based Synthetic Drilling Fluids' Volumetric Behavior Under Downhole Conditions
Authors: Demirdal Barkim , Cunha J. C.
Published: December 2007

Usual practice in drilling engineering is to determine drilling fluid density at surface conditions assuming that drilling fluid density does not change with changing downhole conditions. This assumption may result in inaccuracy while estimating static and dynamic pressures in the wellbore especially when synthetic based drilling fluids are used. Inaccurate estimation of pressure profile in the annulus can lead to severe well problems such as kicks, drilling fluid losses and wellbore instability. In addition, inaccurate pressure profile estimation can affect the success of Managed Pressure Drilling (MPD) operations which require real time knowledge of wellbore pressures in order to keep it between formation pore and fracture pressures using a control choke placed on the return line of the annulus.

Effects of pressure and temperature on volumetric behavior of two olefin based synthetic oils are investigated in this study using a mercury free PVT system. The olefin based synthetic oils used in this study are C16C18 internal olefin and C12C14 linear alpha olefin. In order to simulate deep offshore situations the temperature is ranged between 25 °C and 175 °C, while the pressure is ranged between 0 psig and 14,000 psig.

In addition, volumetric performances of olefin based synthetic oil systems under investigation are compared with those of water, brine solution, mineral oil, diesel oil and n-paraffin based oil under similar conditions.

The study shows that synthetic based oils' volumetric properties are more sensitive to pressure and temperature conditions compared to water, brine solutions, mineral oil and diesel oil. Once emulsion systems containing synthetic based oils are used, density change with respect to downhole conditions should be modeled to increase the reliability of pressure profile calculations.
Seeing Beyond the Frac: Integration of Hydraulic Fracture Mapping With Multi-Component 3D Seismic Data
Authors: Shemeta J. E. , Davis T. L. , Roth M. , Riley R. B.
Published: December 2007

The Colorado School of Mines Reservoir Characterization Project (RCP) has performed a multi-year study of the Rulison Field in the Piceance Basin, Colorado in cooperation with the Williams Production Company. Rulison is a gas field producing from the Williams Fork Formation, which is part of the Mesaverde Group and consists of stacked fluvial sandstones. Commercial production in Rulison depends on hydraulic fracture (frac) stimulation, typically multiple stages targeting sands and some coals in the lower section of the formation. During fracing, the induced seismicity was recorded using borehole geophones as part of the 2006 RCP field campaign at Rulison. 3D surface seismic surveys collected over multiple years at Rulison are being used to characterize the faulting and natural fracture distribution within the field. This paper discusses integration of the hydraulic fracture microsesimic mapping results with 3D seismic volumes, which provides insight into hydraulic fracture growth and geometry and additional information for short and long term reservoir management.
Multiple-Zone Completion in Marginal Production Wells
Authors: Pitrelli Guillermo , Giraldo Maximiliano
Published: December 2007

Concepts on well multiple zone completion systems applied in marginal wells in Los Perales Oil Field, located in the Gulf of San Jorge Basin, Santa Cruz province Argentina. The field is fully operated by Repsol-YPF.

The paper narrates the challenge and experience of completing three marginal production wells (LP-2384, LP-2354 and Hue.xp-10), using concepts on well zone isolation, flow control capability, production management and easy well access in future workovers. The field is characterized by a stratified reservoir which is created by changes in depositional condition therefore each layer has different rock properties and flow characteristics (fluvial type reservoir). Gas oil and water are being produced commingle from different layers. The traditional method used to avoid production of a specific layer was cementing the layer or leaving it below a drillable plug (type N-plug). Despite difficulties, three wells were completed based on these concepts:

LP-2354: Selective zone completions, allowing reservoir and production management of three different gas sand beds.

LP-2384: Selective isolation of gas and water sand layers. Oil zone was put into production, allowing for ultimate gas recovery using pulling rig and a wireline unit instead of a workover recompletion.

Hue.xp-10: Gas ultimate recovery increased with a rig less workover completion. Killing the well, thus damaging the formation, was avoided.

Each well completion and intervention was designed, based on a cost effective and fit for purpose, criteria. Different arrays of tools (straddle retrievable packers, side pockets mandrels, mandrel valves and tubing screens) were run into the wells.

The main enhancements were the following:

Cost-effective rig less workover. Higher artificial lift performance by avoiding commingled flow using multiple zone isolation (no gas pound on the pump, no unwanted producing fluids). Cross flow and formation damage prevention due to commingled production. Easy well access to increase gas ultimate recovery, using a pulling rig instead of a workover recompletion. Recompletion of gas wells by means of wireline conveyed casing guns and wireline setting packers without killing the well in order to pull down tubing string and therefore preventing formation damage.
A More General Capillary Pressure Curve and Its Estimation From Production Data
Authors: Gang Tao , Kelkar Mohan
Published: December 2007

Capillary pressure plays a very important role in naturally fractured reservoirs. The exchange of fluids between matrix and fracture is essentially dependent on capillary pressure expressed by the capillary pressure curve. Capillary force may contribute to the displacement process through imbibition process, or may oppose it in the drainage displacement process.

It is essential to represent the capillary pressure curves properly. Many capillary pressure correlations have been suggested in the literature. Capillary pressure data were normally measured using core data. However these methods suffer limitation due to the scale over which the data were collected. Therefore it will be very useful if the capillary pressure curve could be extracted from production data through the history matching process.

This paper presents a simple and generalized capillary pressure model which captures both the spontaneous and forced parts of the imbibition capillary pressure curve. In addition, the capillary pressure was estimated by the production data. The sensitivities of production data with respect to capillary pressure model parameters are required when the gradient-based optimization algorithm is used to minimize the objective function. How to calculate the sensitivities of the production data with respect to the capillary pressure model parameters is provided. By minimizing the objective function which describes the mismatch of the observed and simulated production data, the water-oil capillary pressure curves are estimated. All of implementations are incorporated into a commercial simulator (ECLIPSE) and iterated in the automatic history matching scheme. The method is validated using many synthetic cases.
Transient Analysis of Flowlines and Slug Catcher Level Control
Authors: Rezzónico R. , Carp A.
Published: December 2007

The feasibility of handling increased flow from an expanded gathering system with the existing slug catcher was analyzed.

Transient analysis simulations for the flowlines were conducted to determine the surge flow at the receiving facilities when changes in flow rates, restart operations and pigging operations occur.

Knowing the surge flow (inlet liquid flow) vs. time, the operating volume of the slug catcher and the drain rate (processing flow) to the plant, it can be determined if the existing slug catcher volume is big enough for handling the flow variations and the incoming slugs for different scenarios.

A PI level controller was proposed to control the level in the slug catcher. It was possible to find the tuning parameters (Gain and Integral Time) in order to keep the liquid volume within the desired levels, avoiding undesirable sudden drain rate changes that are difficult to handle in the process units downstream of the slug catcher. Several operating cases were analyzed and it was concluded that pigging cases, especially those for the lowest gas flow rates, produce the biggest slugs. A properly tuned PI level controller helps to optimize the slug catcher volume.

The conclusions of this study are applicable to Gas Oil Separation Plants.
Evaluating and Developing Tight Gas Reserves—Best Practices
Authors: Stotts Garth W. J. , Anderson David M. , Mattar Louis
Published: December 2007

Tight gas is becoming an increasingly important asset for petroleum companies. Proper reservoir evaluation and development planning is critical to the success of a tight gas play. To date, the "best practices" for evaluating tight gas performance have not been well defined, and many companies use unreliable or unnecessary methods. As a result, analysts commonly misinterpret (and incorrectly book) tight gas reserves. Furthermore, the development of tight gas reservoirs is often conducted inefficiently, either through over-capitalization (too many wells, too quickly) or ineffective recovery (overly sparse spacing).

This paper presents a straight forward and technically sound approach for evaluating and planning the development of tight gas reservoirs. The critical step in the process is proper identification of the dominant reservoir flow regime. Without this step, we cannot choose the correct analysis plot to use. The techniques detailed in this paper are designed for production data sets ranging from about 3 months and upward. The reservoir and production characteristics (permeability, xf, flow regime) are determined using pressure/rate transient analysis, as are the drainage region and its expansion rate. The resulting model predicts well performance and the rate of increase of accessible recovery over time. Superposition of the appropriate economic model and well constraints allows the analyst to identify a practical range of EUR values that is more reliable than that provided by conventional decline curves. This process can be applied to reserve evaluation as well as optimizing well spacing in the reservoir. The analysis is performed through interpretation of a diagnostic plot paired with an appropriate recovery plot (using well constraints and economics). It is validated using simulated and field examples.
Transient Flow in Discretely Fractured Porous Media
Authors: Izadi M. , Yildiz T.
Published: December 2007

This paper presents an analytical study of transient flow into multiple vertical wells producing from a porous media containing randomly distributed discrete fractures. The model may be used to analyze the production and well test data from tight gas sands and Austin chalk type reservoirs. Both vertical openholes and hydraulically fractured vertical wells are considered. Wells and fractures are randomly distributed. The model dynamically couples the multiple fracture flow models with an analytical reservoir flow model. The analytical model simulates pressure and pressure derivative characteristics of wells and flow distribution along and through both the natural and hydraulic fractures.

The study shows that single or multiple isolated fractures yield negative pseudoskin factors in vertical wells near isolated fractures. The negative pseudoskin factor in unstimulated wells has also been observed in field tests. The negative pseudoskin factor is a function of fracture conductivity, fracture density, length, distance from the wellbore, and azimuth.

Using the model, we demonstrate that the shape of pressure derivative is related to fracture distribution. However, the wellbore pressure derivative response is controlled by the fractures in the near wellbore region.

The result of this study indicate that the conventional analysis, based on the double porosity model such as the Warren and Root model, to predict the storativity ratio of a naturally fractured system is not reliable. Also, the displacement between two semilog straight lines is not necessarily a good indicator of the storativity ratio.
Evolution of Stimulation Jobs, Block X, Talara Basin, Perú
Authors: Sánchez Luis , Palomino Daniel , Mercado José , Díaz Tomás
Published: December 2007

Peru has a great background in the oil industry; the first well in South America was drilled in Zorritos, located on the northwest coast of Peru, in 1863. Originally, the wells were completed in the shallower pays with cemented casing and using perforated liners in the productive areas. Production was driven by the natural energy of the reservoirs.

Around 4600 wells have been drilled In Block X and, currently, there are 2021 producing wells, with an average production of 6.4 bls./day per well. Hydraulic fracturing is required to produce them economically.

These works have been done since 1953, and continue up to the present applying available technical innovations. Initially, stimulations were carried out through hydraulic fracturing using diverse multifrac techniques, with crude oil as base fluid. In the 90's, oil was substituted for water as a base fluid for stimulations, to generate better fractures and increase recoveries.

In spite of the maturity of Block X and the high wells density, new alternatives were searched in order to continue operating economically, considering:

□ Re-fracturing wells, in intervals of higher pays (500-1200 ft.) with low initial fracture efficiency □ Use of low cost local market sand that will allow to obtain significant savings. □ Reduction of polymeric load in fracturing fluids ranging 15 to 25 lb/mgal. □ Evaluation of new technologies (ultra light support agent and visco elastic fluids) to improve well productivity.

In this paper a historical perspective as well as currently applied technologies for stimulation are reviewed, and related field results are presented.
Smart Fields® — Optimizing Existing Fields
Authors: van den Berg Frans G.
Published: December 2007

In a Smart Field, the asset staff has the tools, processes and skills to maximise the asset lifecycle value, and do this on a continuous basis. This involves optimisation at several time scales, in production, reservoir management and development planning. Shell has a programme of technology development and implementation on a global scale to achieve this vision.
New 4D-Seismic Monitoring Techniques as Enablers for Smart Fields
Authors: Calvert Rodney , Bakulin Andrey
Published: December 2007

New 4D seismic methods have been developed that can greatly improve the sensitivity, speed and economy of more continuous monitoring for field control. They will increase the range of fields that can be monitored and benefit from enhanced recovery.
Advanced Heated Annulus Drive Technology: An Emerging Technology Compatible with Directional Drilling to Improve Recovery from Tar-Sand Reservoirs
Authors: Wajid Ali
Published: December 2007

Petroleum industry is technology driven. Any new strategy which is economically feasible and promotes sustainable development of oil and gas resources while respecting human safety and the environment, is a welcome change. "Advanced Heated Annulus Drive Technology" is one such field of development to produce oil from subsurface tar sand/heavy oil reservoirs. In this paper the said technology has been discussed keeping in view the above mentioned factors (i.e. economics, safety and environment).

This technology is disclosed for producing viscous petroleum. The method employs a vertical and a horizontal well through the petroleum deposit. A combination of injection procedures, through the horizontal and vertical well, heats the viscous petroleum in the annulus around the horizontal well. Successive completion intervals are installed in the horizontal well to produce the heated petroleum. The petroleum is driven by a drive fluid passing through previously produced intervals.

This technique is the best of previously described techniques for the recovery of oil from tar sand reservoirs. Previous proposals for the recovery of significant percentages of the petroleum in place have required a large number of vertical wells at very close spacing. While in the present proposal, most of the vertical wells are eliminated thereby greatly improving the development economics.

Heavy oils are a major potential source of future reserve renewal for the petroleum industry. Access to these reserves demands innovative production techniques that are more competitive than those already known. "Advanced Heated Annulus Drive Technology" may be regarded as a competitive technology of current era, for tar sand reservoirs.
Stochastic Modeling and Uncertainty Analysis of Mature Fields
Authors: Campozana F. P. , Backheuser Y. , Antunes R. F. , Camoleze Z.
Published: December 2007

Nowadays two things are absolutely crucial in petroleum industry: (1) an integrated approach from seismic to reservoir simulation (history matching included) and (2) uncertainty and risk analysis. The first one ensures that the model is coherent with all types of data and the second one drives decision and quantifies risk. Current available hardware and software allow simulating stochastic models with statistical analysis of multiple scenarios. It is important to have a standard workflow that takes into account both aspects and can be applied to all projects. Although geophysicists may not be used to, it is important to include uncertainty analysis on the geophysical model too.

A mature field located in Brazil is used as an example to illustrate the approach suggested above. The field has produced more than 20 million bbl of light oil and now a complementary project development is under study. Despite the amount of oil that has been produced, a significant geological uncertainty still remains. To provide the asset managers with a realistic range of possible outcomes of a project development, a thorough geological stochastic modeling was conducted. Four thousand models were generated considering the following varying parameters: reservoir structure, oil/water contact, porosity, net-to-gross, and initial water saturation. The models were ranked by VOIP and the distribution was sampled (P1, P2, … P100) to go through numerical flow simulation. Permeability uncertainty was introduced by considering two possible scenarios for each model, giving a total of 200 reservoir models. Dynamic data was compared to simulation results through an objective function and those models which gave results too far away from production history were discarded. The VOIP distribution was recalculated.

From this new distribution, the P10, P50, and P90 realizations were picked to be history matched. After that, 27 models were generated through experimental design to consider the variation in the following parameters: (1) geological model, (2) relative permeability, (3) absolute permeability, (4) well productivity index, and (5) the number of wells to be drilled in the project development. The second and third parameters were kept constant in the vicinity of the producing wells so that all 27 models honored production data. A response surface model was generated by interpolation of the 27 flow simulations to obtain 10.000 outcomes for different parameter values. From these results it was possible to perform uncertainty analysis on the prediction.
Influences of Gamma Ray Irradiation on Thermal Decomposition and Petrophysical Properties of Carbonate Rocks
Authors: Shedid Shedid A.
Published: December 2007

Gamma rays are bursts of high-energy electromagnetic waves that are emitted naturally by some radioactive elements. Laboratory experiments were undertaken to assess the influences of gamma irradiation on thermal decomposition and petrophysical properties of carbonate rocks of aquifers and oil reservoirs. A constant gamma ray dose of 9 MGy was applied on identical calcium carbonate core samples, extracted from actual oil reservoir. The core samples were analyzed using thermogravimetric analysis (TGA), differential thermal analysis (DTA), infrared spectrum (IR) and scanning electron microscope (SEM) before and after application of gamma ray irradiation. The attained data was used to interpret thermal decomposition, phase transition and mechanical stability of calcium carbonate rocks. Furthermore the effect of gamma irradiation on pertophysical properties of porosity and permeability were studied experimentally for water and oil saturated carbonate rocks.

Chemical composition of the carbonate core samples was determined using titration method and its sulfur content was determined using precipitation method. Application of Differential Thermal Analysis (DTA) proved the purification of the used core samples. Chemical analysis indicated that the core ha 99.8 % calcium carbonate. The Infrared (IR) indicated that no chemical changes of irradiated core samples have been observed. The analysis using DTA and TGA indicated that gamma irradiation enhanced thermal decomposition of carbonate rocks of oil reservoirs. The obtained results indicated that calcium carbonate rocks are stable rocks. In addition, the gamma ray irradiation has been proven to have almost no effect on porosity and permeability of these reservoir rocks.

Applications of the attained results are expected to have real impact on deep understanding of rock stability, using gamma ray tools and measuring gamma ray levels in oil fields, and improvements in future interpretation of attained data from gamma ray measurements such as gamma ray log.
Optimization of Deepwater Drilling with Real-Time Operations
Authors: Hamed Walid , Bassem Ahmed , Gamal Medhat , Nafie Sherif , Oraby Moustafa , Waheed Arshad
Published: December 2007

The following-up of drilling operations in "real time" from a remote location has been on the wish list of some drillers for quite a long time. In recent years, this has become a reality with phenomenal advances in digital technologies, satellite communications, remotely controlled systems, and collaboration centers that allow locations in different parts of the world to follow up on an operation on a round-the-clock basis.

The primary objective for the exploration drilling of oil and gas wells is to find and develop new energy sources that can meet the energy demands of the future. It is also universally accepted that this objective must be met safely and efficiently.

Real-time operations go a long way toward ensuring safety for the oilfield; the ability to remotely monitor operations avoids the need for experts or other non-essential people on location. This reduces the exposure risks associated with travel or rigsite presence for a number of people. The safety factor extends beyond the physical transportation or presence of individuals at a work location because, by monitoring subsurface pore pressure trends, shallow flow hazards can be detected early and a recourse taken. The well is essentially under the discernible watch of several experts at critical points ensuring the delivery of a safe and efficient well.

Several other operational benefits can be realized from real-time operations. This paper discusses several of the tangible gains realized from this type of operation and the future it holds for its users.
Expandable-Drilling-Liner Technology: First Commercial Deployment of a Monobore Liner Extension
Authors: Stockmeyer Carl F. , Adam Mark K. , Emerson Alan B. , Baker Robert V. , Coolidge Robert B.
Published: December 2007

For a number of years the E&P industry has sought to prove the feasibility of monobore expandable liner extensions as an advantageous alternative to the "telescoping" nature of conventional casing designs (Figure 1). Collaboration between an operator and a supplier has produced a system that accomplishes this purpose for a 9 5/8" or 9 7/8" parent casing string to maintain 8 ½" drift post-expansion. Utilization of this well construction product can be planned as either a basis of casing design, or as a planned contingency.

Figure #1 Casing Designs

The objective and value of the monobore extension enables the operator to implement one more casing string, without reducing hole size. As a basis of design, this technology provides the option for the operator to begin well construction with one smaller casing size, which may drive down costs significantly, especially in high cost drilling and "floater" drilling programs. As a contingency, the product can isolate trouble zones such as reactive shales, sub-salt rubble zones, and low fracture gradient transitions without being forced to reduce casing size and subsequent drilled hole size. This capability can yield immeasurable benefits when retaining hole size means being able to either evaluate the reservoir as fully as desired, or to produce wells at rates deemed commercially necessary and optimum.

The technology development collaboration produced a one-trip, top-down expansion system that was developed, tested and proved the technical feasibility of the expandable monobore liner extension concept.

This paper details:

➢ Key System Features and Benefits ➢ System Development Downhole recess shoe qualification Casing selection qualification Zonal Isolation Requirements Monobore liner extension selection, one trip system ➢ Field Trial Pre-planning Expansion Process Post deployment results ➢ Planned Contingency Applications ➢ Casing BOD (Basis of Design) Applications ➢ Summary
Underbalanced Perforation and Completion of a Long Horizontal Well: A Case History
Authors: Bowling J. , Khan M. , Mansell M. , Balushi H. , Somat E.
Published: December 2007

A clastic reservoir in central Oman is to be developed with some 100 wells. The rock is sensitive to formation damage and experience shows that productivity is improved by a factor of 10 by perforating with deep-penetrating charges underbalanced and avoiding contact of brine with the formation. The wells will be horizontal to drain a 24.5m oil rim, and zonal isolation for future water and gas shutoff is desirable.

An interval of 600 meters was perforated with 4 ½" OD guns. The guns were retrieved under pressure and a lower completion packer was run to isolate the reservoir from the surface. The upper completion was run with crude in the hole to ensure that no brine should contact the formation.

To perforate underbalanced with a drilling rig, the well was constructed with a 7" liner at the start of the build section to total depth of the well. A 7" tie-back was run with a surface controlled downhole isolation valve (DHIV) as a barrier after perforating. The well was displaced to crude to create underbalance. A 7" predrilled liner joint was run beneath the DHIV in the work string to allow circulating out well bore fluids so that the guns could be retrieved safely. A rotating control head and underbalanced drilling surface equipment package was utilized for stripping with 8,000 kPa surface pressure bleed off volumes for tripping and manage the crude circulating system. The tie-back was retrieved and the upper completion was run after setting a plugged packer in the 7" liner. This method is unique because it utilized a conventional drilling rig for completion operations along with an underbalanced drilling package to perforate and complete the well underbalanced.
Parametric Analysis of MPD Hydraulics
Authors: Tian Shifeng , Medley George , Stone C. Rick
Published: December 2007

Managed pressure drilling is a process that utilizes friction pressure and annular back-pressure in addition to conventional hydrostatic column pressure to allow drilling of difficult formations. There are many parameters that play a part in the managing of wellbore pressure during fluid flow. Wellbore pressures are impacted by fluid density and rheologic properties, injection rates, cuttings transport, influx while drilling, wellhead or choke pressure, hole geometry and drillstring configuration. The effects of these parameters on wellbore pressure are different, but interact with one another. Therefore, careful consideration is needed when choosing which parameter(s) should be adjusted to manage the wellbore pressure during any particular operation.

A good understanding of the effects of these operating parameters on wellbore pressure is essential in the optimum design of an MPD project. This is especially true of the rheologic properties of MPD fluids. Rheologic properties of drilling fluids play important roles in the variation of wellbore pressure during any MPD operation. Most drilling fluids (WBM, SBM, or OBM) currently used in the field have a nonzero yield point (YP). A non-zero YP causes a sudden bottom hole pressure (BHP) jump when fluid starts to move or when fluid is about to stop moving. It also causes a sudden BHP jump when the drillstring starts to move up or down during tripping or connections regardless of how slow the pipe moves. The sudden pressure jump makes it difficult to minimize BHP variations.

This paper discusses the effects of various operating parameters on wellbore pressure and provides guidelines for managing wellbore pressure by adjusting those operating parameters. A simple equation to predict the sudden pressure jump caused by YP is provided. Field cases are used to illustrate managing wellbore pressure by adjusting various operating parameters.
Air Drilling in the Presence of Hydrocarbons: A Time for Pause
Authors: Malloy Kenneth P. , Medley George H. , Stone C. Rick
Published: December 2007

Drilling with compressed air continues to enjoy vast popularity. It is often the application of choice in dry, hard rock because the drilling fluid medium is inexpensive and, compared to water or weighted drilling mud, respectable rates of penetration can be achieved. In terms of economic considerations with respect to drilling fluid expenditures, air drilling has virtually no equal. However air drilling is not without its impediments; not the least of which is its reactivity with hydrocarbons.
Learnings from Implementing the Occupational Hygiene Program in Chevron Thailand
Authors: Rungruang Surapat
Published: December 2007

The Chevron Thailand Industrial Hygiene Monitoring Program has been developed and implemented since mid-1980’s with the aim to comply with both the recognized standards and local regulations, but more importantly to protect the health of all workforce while working with the company.

During this 26-year period of industrial hygiene program implementation, significant numbers of industrial hygiene samplings have been taken from different workforce group in a vieriety of locations.

Over the past years, many baseline sampling and monitoring initiatives have been conducted to identify specific problem areas. The monitoring strategy, health risk mitigations and controls were based on the numbers of samples colleced during that period. During the early 90’s an annual industrial hygiene monitoring plan were developed and issued prior to identifying and qualtifying job specific hazard exposure.
Assessing the Potential Production of a Tidal Current Energy Project
Authors: Ruer Jacques
Published: December 2007

The renewable resource of tidal current is presently attracting the interest of many companies. Several systems are in the development stage and SAIPEM is participating in one of them.

The tidal streams are predictable well in advance but are variable along the hours and the days. In order to determine how much energy can be produced during a year, a model has been written. It takes into account the local current characteristics and the astronomical evolution of the tide during a whole year. This model indicates how to select the nominal electrical capacity of the tidal turbine in order to optimize the energy cost of the scheme. The model teaches that a turbine located in a tidal race off the European coast has an equivalent number of producing hours of about 3000h per year as an average.

In some locations, the site may be exposed to the swell in addition to the tidal currents. A tidal current turbine reacts almost instantaneously to the velocity variations, because the inertia of the turbine is small compared to the inertia of the water flow crossing the rotor. This results in power fluctuations of a single turbine, at least as long as the water velocity does not exceeds the nominal rating of the machine. Some examples are shown to illustrate the different cases. The local wave climate should be taken into account in order to correct the yearly production on a statistical basis. The potential influence of a strong swell may alter the maximum power predicted based on the sole astronomical parameters.

Clusters of tidal turbines have also been studied. The detrimental influence of the swell can be mitigated through an optimum design of the turbine array. When the current is slow and the swell important, the cluster can even produce more energy than without the waves.
Enhanced-Oil-Recovery Potential of Heavy-Oil Fields in Africa
Authors: Yee Hon Vai , Kechut Nor Idah , Razak Wan Nurul Adyani W
Published: December 2007

This paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation.

The data required for the study include: 1) fluids and rock properties; 2) driving mechanism; 3) production data; 4) OOIP and recoverable reserves; and 5) relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations1. The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs.

The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields.

Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields.
Spreadsheet Simulators that Demonstrate how Statistics can Lie about Safety Performance
Authors: Veley Carl
Published: December 2007

The science of statistical analysis uses advanced mathematics beyond the capabilities of most people, but the principles behind those high level equations are essential in understanding the role of chance in conventional safety performance metrics. A series of spreadsheets has been developed to illustrate some of the essential principles, without utilizing the daunting rigorous mathematical proofs. Readers who experiment with these spreadsheet simulators may be surprised to find some of their routine or basic assumptions about safety statistics are actually scientifically indefensible. Studying the principles illustrated by these simulators may suggest needed modifications to common industrial safety programs.
The Growth of Online Oil in Water Monitoring and Statoil's Experience on the Sleipner A Platform
Authors: Aanensen Geir
Published: December 2007

The increase in produced water has led to a growing need from E&P operators for better oil in water monitoring systems. Roxar has developed an inline and online oil-in-water monitor suitable for topside discharge and re-injection applications, based on ultrasonic technology.

The first Roxar Oil-in-water monitor was installed in May 2006 on Statoil's Sleipner A platform in the North Sea. Statoil is using the monitor to measure overboard water discharge, ensuring that it meets environmental requirements and efficiently monitors the separation process.

Immediately after installation, attempts were made to introduce increasing amounts of oil into the produced water stream to verify that the monitor registered oil concentration changes accordingly, which it did. Periods with distinctly higher concentration levels were also analyzed. The rapid change in water level in the separators corresponded to an increase in the oil-in-water concentration downstream. During the trial phase, reliability and robustness have been demonstrated, and this paper describes how the ultrasonic measurement techniques, combined with a novel reflector design, helps the operator obtain accurate oil concentration readings even during and after experiencing production instability.

This paper presents results from the pilot, verifying the performance of online oil in water monitoring and its ability to operate at different concentrations.

The pilot to date has confirmed the monitor's ability to provide accurate information to Statoil on the size distribution and concentration of oil and is already playing a key role in monitoring Statoil's overboard discharge and separation process.
Occupational Illness: Challenges Faced
Authors: Kumar Surya
Published: December 2007

What is Occupational Health?

A simple definition of health is as follows: "a state of physical, mental and spiritual well-being". Occupational health is a state of such well-being at the workplace. Occupational health comprises three main components. They include occupational illnesses, illnesses that can be affected by factors at the workplace and illnesses that are unlikely to be affected by the workplace. Examples of occupational illnesses include lead poisoning, asbestosis and noise-induced deafness. Illnesses that may be affected by workplace factors include asthma and some liver diseases, depending on exposures in the working environment. Although technically possible in some cases, many medical conditions are not usually affected by factors within most workplaces. These include lifestyle-associated and hereditary diseases such as diabetes and high blood pressure.

Health Determinants

What determines your health? Firstly, one’s genes or who you are play a very important role. A family history of certain illnesses enables us to predict one’s risk of certain diseases such as diabetes and high blood pressure and cancers such as breast and cervical cancer. Secondly, one’s lifestyle and habits such as diet, exercise and smoking do, of, course change your risk for certain lifestyle-associated diseases. Health promotion takes care of this element. Thirdly, factors in the environment, including the work environment, can determine one’s health as well. We need to protect individuals, including the worker, from these adverse factors.

Occupational Health

Occupational Health involves predicting vulnerabilities, promoting good health and protecting the workforce. Exposure levels of many substances in the workplace can be much higher than those in general environment. Occupational health deserves more focus because ill-health effects may not manifest for a long period of time. The Health Risk Assessment identifies, evaluates and seek ways to control the impact of occupational risks on the worker; hence preventing illnesses that can be acquired through such direct workplace exposures. A responsible company goes beyond occupational health to promote general health and well-being.
Systematic Investigation of Waterflood Reducing Residual Oil Saturations by Increasing Differential Pressures at Various Wettabilities
Authors: Johannesen Else B. , Graue Arne
Published: December 2007

The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at increasing constant pressures were carried out to determine the relation between remaining oil and applied capillary number in waterfloods at different wettability conditions.

Various uniform distributed mixed wettability conditions were established and quantified by the Amott test for 21 core plug samples. Minimum remaining oil at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The residual oil saturation decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery.