bluuebunny/crossref_metadata_2025 huggingface dataset:
Well Sanding and Lost Production due to Cyclic Water Hammer
Authors: Hayatdavoudi A.
Published: December 2007

This paper describes our recent observations relative to the repeated shut-ins of the high-pressure oil and gas wells in the Gulf of Mexico. The current Mineral Management Service regulation requires that in the case of an emergency such as hurricanes, fires, spills, pipeline problems, etc., the subsurface safety valve slam shut in 45 seconds but the flapper at the end of its travel actually slams instantaneously against the well flowing pressure. The type of subsurface safety valve installed for this purpose is a flapper, which is kept open by an hydraulically activated spring. Once the spring receives the triggering signal, it will close the flapper instantaneously. The instantaneous shut-in appears to cause a water hammer effect in the form of strong cyclic peak pressure, which travels down the tubing into the perforations. This extra pressure builds up cyclically in the reservoir rock near the well bore until it is attenuated with time. After the emergency condition has passed, the operator puts the well back on production. We have observed, at least in three deep wells with highly consolidated reservoir rocks, that not only did they lose fluid production, but they also produced a great deal of pulverized, highly angular rock fragments. The microscopic analysis of the rock fragments show patterns of reflected and propagated tension fractures, stick-slip sheared surfaces, and catastrophic failures of silica, feldspars, and various types of grain-bonding cements such as siderite. We have concluded that the wells lost production due to well sanding and that the well sanding was induced by cyclic hammering pressure and cyclically induced and propagated micro fractures extending all the way into the water bearing formation below or above the producing zone. Furthermore, these induced Hammering Waves detrimentally changed the cyclic effective stresses around the perforations.
Downhole Fluid Analysis and Fluid Comparison Algorithm as an Aid to Reservoir Characterization
Authors: Venkataramanan L. , Elshahawi H. , McKinney D. , Flannery M. , Hashem M. , Mullins O. C.
Published: December 2007

In recent years, formation sampling and testing tools have provided a variety of new downhole optical measurements for downhole fluid analysis (DFA). DFA involves in-situ measurement of optical absorption spectra used to compute properties such as hydrocarbon composition and gas oil ratio (GOR). Abrupt changes in these fluid properties with depth may be a marker for reservoir compartmentalization. However, hydrocarbon differences can be reliably identified only when the significance of uncertainties due to measurement and oil base mud filtrate has been taken into account. Recently, an algorithm called the fluid comparison algorithm (FCA) has been developed to address this issue.

FCA propagates uncertainties in optical measurement and contamination into uncertainties in fluid properties, such as color, composition, and GOR. The output of FCA is the probability that two fluids are statistically different. Real-time application of FCA can optimize capture of downhole fluid samples and generation of a continuous downhole fluid log representing the fluid complexity in the reservoir. In addition, by identifying abrupt changes in fluid properties with depth, FCA may in some circumstances be an assay for reservoir compartmentalization.

In this paper, we briefly review the theory of FCA. The strengths and limitations of the technique to improve understanding of reservoir architecture and fluid complexities are presented through two case-studies.
History Matching of the Valhall Field Using a Global Optimization Method and Uncertainty Assessment
Authors: Al-Shamma B. R. , Teigland R.
Published: December 2007

This paper provides a study of a history match on a complex reservoir model using a global optimization method. This is done by applying Evolutionary Algorithms to the problem of history matching. The results of the history match are then used to carry out an uncertainty assessment on variables of interest. The main parameters used in the history match included: horizontal permeabilities, porosities and vertical transmissibilities.

This study also made use of methods for improving the convergence of the optimization cycle, which included using correlations, adopting a Bayesian approach and exploring the search space. The results obtained over the optimization cycle, are used to identify sensitivity parameters, correlations and parameter trends in a global search space. In addition the original manual history match was further improved by adopting a pressure match using an Evolutionary Strategy. Best matched cases were selected based on the global and partial objective values of each match. Predictions runs were performed in order to investigate the effect on the cumulative oil produced and the STOIIP.

Finally an uncertainty assessment of the most recent history match was carried out using an experimental design matrix. The results of the experimental design were used to generate a proxy, which is used in a Monte Carlo simulation to develop P10/P50/P90 oil forecasts.
Predicting Deepwater Well Behavior
Authors: Al Kindi Azhar
Published: December 2007

In comparison to on-shore or shallow water fields, there is limited experience in the industry for deepwater well performance prediction. The development of deep offshore reservoirs is a high risk exercise: in addition to commercial and environmental exposure, the sparsity of early exploration data compounds with the inherent geological complexity of turbiditic formations, making any performance prediction, and therefore development planning, highly uncertain.

Prediction of a well performance is generally a twofold matter: predicting the initial rate of the well and the longevity of the well. Historical information is often extremely useful in such an exercise. In a Deepwater field in the Gulf of Mexico, understanding the behavior of existing wells and reasons for their historical deviations from prediction has formed a major input into the design of the next Phase development wells.

While the new technologies that are emerging for deepwater primarily encompass the areas of drilling and completions, and subsea systems, technologies addressing subsurface uncertainties are also rapidly surfacing. The understanding of some of the major subsurface challenges, such as compaction, compartmentalization and completion failures has, naturally, evolved as new related technologies evolved.

Technological advances in the area of 4D seismic have enhanced the understanding of underground water movement and the distribution of depletion patterns. And while fault density, position, extent, direction and transmissibility remain a large uncertainty in most GOM fields, the application of state-of-the-art seismic processing and simulation technologies is believed to be a major contributor towards the mitigation of such.

Reservoir sand quality and fluid properties have, typically, dictated certain completion designs for wells and a certain operating philosophy. Another example of advanced technology implementation, in GOM multi reservoir setting, is the deployment of an integrated field-planning tool, linking individual reservoir models to a surface facility network model. This tool manages overall system flow parameters, thus, enhancing the predictability of the field performance.

The focus of this paper is to address the challenges associated with performance prediction for deepwater wells and the techniques used to mitigate such challenges, as related to GOM fields.
The Role of Conceptual Geological Models in More Accurately Estimating Inplace Hydrocarbon: An Example From the Cooper Basin, South Australia
Authors: Al-Khalifa M. A. , Payenberg T. H. D. , Lang S.
Published: December 2007

The generating and usage of conceptual geological models become an integral part of reservoir characterisation studies, because they represent geologist understanding of the reservoir. With understanding of uncertainty associated with the conceptual models, their usage could be expanded to accomplish critical task such as inplace hydrocarbon (IPH) estimation. This paper presents a recommended workflow for building a conceptual geological model for a fluvial system and discusses the different uncertainties associated with it. Afterward, Its uses this workflow to build a conceptual geological model for a gas reservoir in the Cooper Basin, South Australia and estimates the IPH through stochastic modeling method.

Building a fully integrated conceptual geological model involves input data of different scales such as core data, well logs and analogues, and each input has its own uncertainty. The process of building a conceptual model is made up of different steps such as core description and depositional facies identifications. Uncertainty cannot be eliminated, but it can be reduced. It cannot be eliminated because the accurate description of the reservoir is not known and will not be known precisely, but using available data will help in narrowing down the possible choices.

Inplace hydrocarbon estimates using stochastic modeling method was preformed for a gas reservoir in the Cooper Basin. There were two stochastic porosity models built using the same input data, but one model was based on a conceptual model and the other was not. The results showed that the use of conceptual models has given higher oil and gas estimates. This is due to the mechanism of the porosity simulation based on geological data. The porosity is simulated independently in each facies object in each reservoir interval. Another advantage of using the conceptual model is improvements in the continuity of porosity. Without the facies objects, porosity continuity will be dependent of semivariograms and values at wells. In the absence of any well data, the continuity will be estimated for the semivariogram parameters namely range and direction.
Uncertainty in Geophysic-Geology-Reservoir Modelling for Globigerinid Sands Carbonate in the NE-Java Basin, Indonesia: Case Study: Planning vs. Actual Field Development in the Madura Strait, Indonesia
Authors: Sutadiwiria G. , Prasetyo H.
Published: December 2007

One of the most challenging problem in the Plan Of Development for developing the Globigerinid sands carbonate reservoir in determining hydrocarbon potential in the reservoir is the management decision for go and no go project.

In the North-East Java Basin Indonesia, Pliocene Globigerinid sands carbonate was proven as oil and gas potential reserves as found in MDA, TSB, O and M fields, which are operated by several PSC (Production Sharing Contract) companies. The last three fields are in the development phase. Uncertainty issues related to structure, stratigraphy, and pore system were critically influential factors for the success level in the development plan of the fields.

In fact, the results from development wells in one of the fields in the offshore of the Madura-Strait, have indicated a significant difference compared to the Plan of Development based on exploration and appraisal wells. The problems were compartment related due to structure-stratigraphy combination; variation of the depth of fluids contacts for each compartment; low-resistivity case in clean-oil zone; extensive fault development; change and correction of hydrocarbon in-place estimation. All issues above will change the economic of the field.

Based on the lesson learn, an extensive analysis was needed to reduce the uncertainty that influence the economic plan of development before the government grants an approval to develop the field or revised the Plan of Development. There were some identified critical factor to increase the success level for the optimal development of carbonate reservoir Globigerinid sands as follows: the 3-D seismic (multi-component) included inversion and attribute analysis, exploration and appraisal well numbers & type, production test data, laboratory analyses, integrated evaluation with other discipline and so on.

Based on the experienced and integrated approach, the real picture of development of any future fields that contain the Globigerinid sands carbonate reservoir with unpredicted uncertainty factors has been solved and made the economic prospect development became more realistic.
Well Test Analysis in Lean Gas Condensate Reservoirs: Theory and Practice
Authors: Gringarten A. C. , Bozorgzadeh M. , Daungkaew S. , Hashemi A.
Published: December 2007

Gas condensate reservoirs exhibit a complex behavior when wells are produced below the dew point, due to the existence of a two-fluid system, reservoir gas and liquid condensate. Different mobility zones develop around the wellbore corresponding respectively to the original gas in place (away from the well), the condensate drop-out, and capillarity number effects (close to the well). Condensate drop-out causes a non-reversible reduction in well productivity, which is compensated in part by capillarity number effects.

All these effects can be identified and quantified from well test data. Tests in condensate reservoirs, however, tend to be difficult to interpret. Build-up and/or drawdown data are usually dominated by wellbore phase redistribution effects and the main analysis challenge is to distinguish between reservoir effects, boundary effects, fluid behavior and wellbore phase redistribution perturbations.

The paper compares theoretical well test behaviors in vertical and horizontal wells as obtained from compositional simulation with actual behaviors selected from more than twenty different gas condensate reservoirs. An interpretation methodology is described, which uses time-lapse analyses, deconvolution and different analytical and numerical tools to identify the probable causes of the pressure data behavior: two-region and three-region analytical composite models to represent the various mobility zones around the wellbore; a voronoi-grid numerical simulator to represent discontinuous boundaries; a multilayered analytical simulator to account for the geological description and a compositional simulator to verify the fluid behavior. It is shown that, in addition to the usual well test analysis results, it is possible to obtain parameters required for reservoir simulation and well productivity forecasting, such as gas relative permeabilities at the end point, critical oil saturation, and the base capillary number.
Managing Structural Integrity for Aging Platform
Authors: Nichols N. W. , Goh T. K. , Bahar H.
Published: December 2007

Petronas Carigali Sdn Bhd (PCSB) is currently operating in excess of 150 Platforms. Of these over 60% have been in operation for more than 20yrs, 20% of platforms have already exceeded 30yrs with several others in the very near future reaching their initial design life (20-25yrs).

Increasing demand to extend the life of these platforms due to further oil/gas discoveries can result in the platform being subjected to higher loading due to required modifications/ upgrading and work-over demands for which the platform may not have been originally designed for. Furthermore, the need to undertake more frequent detail inspections due to long-term fatigue phenomena also requires managing.

In addition to the above PCSB platforms may also be faced with other challenges/events such as more onerous code requirements, increase in environmental metocean loading, presence of shallow gas and seismic/earthquake loading for which again the structure may have not been initially designed for. As such PCSB must be able to manage these events and justify the on going integrity and fitness for purpose of its platforms.

This paper describes the challenges and solutions faced in managing the ongoing long-term structural integrity of its ageing platforms. Several key assessment procedures, tools and technology initiative improvement programs will be covered in detailed to highlight their importance in managing the long-term integrity of the structures. In addition the implementation of such assessment procedures, tools and technology improvements are being used to assist in the ongoing development of a Carigali Structural Integrity Management System (CSIMS). The process adopted (as described in this paper) is to be inline with the recent development of a standalone Recommended Practice (RP) API RP 2SIM, for the Structural Integrity Management of existing structures (currently applicable to Gulf of Mexico), to extend its applicability to Non-US Waters. As such PCSB has recently joined a JIP (Joint Industry Project) initiative involving a number of Non-US Oil/Gas Operators to extend the applicability of the RP 2SIM to Non-US Waters.
New Integration Technique for Different Type of Data to Construct a Permeability Prediction Model from Well Logs
Authors: Otake Mayu , Shimamoto Tatsuo
Published: December 2007

This paper presents a new technique to integrate the different scales of data, Logs and PLT (Production Logging Tool). Low resolution of permeability measured by PLT (PLT permeability), which is about 10 times lower than that of logs, caused poor correlations among logs and permeability using any regression algorithms. In order to overcome this problem, PLT permeability was down scaled to the log scale and built a correlation using the ACE (alternating conditional expectation) algorithm. The log-derived permeability by this technique can express the complicate variation of permeability at the range of 0.001md to 1md. The result shows a good agreement with not only the PLT survey result and core data but also the mobility measured by wire-line formation tester (RFT or MDT).
Depositional Modelling of Champion Field, Brunei: Assessing the Impact of Reservoir Architecture on Secondary Recovery
Authors: Hadley D. F. , Arochukwu E. , Nishi K. , Sarginson M. , Salleh H. , Omar M.
Published: December 2007

Champion is a multi-billion bbl STOIIP oilfield offshore Brunei. It is a mature field with over 250 producing wells. Oil production commenced in 1972, and production to date is less than 20% of the oil initially in place. The feasibility of increasing recovery through a major waterflooding programme is currently under evaluation. Potential incremental oil recovery is 8%.

Significant capital investment (up to 140 new wells and 10 new jackets) will be required to realise this opportunity. It is, therefore, important to capture the full range of possible subsurface scenarios early in the study. A fundamental first step in the integrated modelling workflow has been to develop an understanding of the depositional and tectonic history of the field in order to create static models that capture the range of uncertainty in geometry and properties of the reservoirs. Data from core, well logs, seismic and outcrop analogues have been integrated to produce depositional models, highlighting uncertainties in reservoir architecture as they would impact potential waterflood recovery. Two broad types of reservoir interval have been recognised:

stacked shoreface parasequences, which form the majority of Champion reservoirs. In general, these comprise a gradational succession from basal offshore-transition zone heterolithics to amalgamated low angle cross-stratified sandstones of the lower shoreface zone. Correctly considering stacking patterns and degree of vertical connectivity between sands is important to the success of a waterflood. tidally-dominated sediments, comprising tidal channel fill or bar complexes set in a background of mud to sand-dominated tidal flat facies have been recognised. For these sediments, channel sand geometry, orientation and internal permeability anisotropy are crucial to predicting fluid flow.

The results of the sedimentological review have been used to create a series of 2D cross sectional dynamic simulation models, covering the range of depositional environments, and a range of connectivity scenarios. The main conclusion of this study is that water is the preferred injection fluid for all of the Champion field reservoir intervals studied. Water typically gives a 15-20% (absolute) higher oil recovery factor than gas.

The impact of the sedimentology review and modelling is that it will enable early selection of water as the injection fluid. This means that surface engineering work can focus on water injection scenarios, reducing the time required to identify a preferred development plan and accelerating project implementation.
An Experimental Study and Genetic Algorithm (GA) Correlation to Explore the Effect of nC5 on Impure CO2 Minimum Miscibility Pressure (MMP)
Authors: Bon J. , Emera M. K. , Sarma H. K.
Published: December 2007

Limited experimental work has been performed to study the effect of nC5 on Minimum Miscibility Pressure (MMP) when added to impure CO2 as an injection gas for flooding processes. Furthermore, current MMP correlations have been developed based on data where the injection gas contains no nC5 fractions. Consequently, their MMP prediction is not highly accurate when nC5 exists in the injection gas. In order to further investigate the effect of nC5 on impure CO2 MMP, this work presents the experimental investigation and subsequent development of a correlation to model this effect.

Using Rising Bubble Apparatus (RBA), MMP data points were measured on three reservoir fluids and four injection gases at three temperatures. The three reservoir fluids were relatively light with stock tank gravities in the range of 44-52 °API and GOR's 100-1300 scf/stb. The base gas composition was 92mol% CO2 and 8mol% C1. To this nC5 was added to create gases with 1mol%, 3mol%, and 5mol% nC5. The nC5 was noted to decrease the MMP.

Based on the experimentally measured MMP data set, a strong trend was found. The effect of addition of nC5 on the impure CO2 MMP has been correlated using Genetic Algorithm (GA). This correlation depends on the injected gas composition and critical properties. The GA-based correlation predicted the nC5 effect with greater accuracy than the currently available correlations, giving an absolute error of only 3.4%.

It is envisaged that this work can be used to investigate the possible benefits in retaining the nC5 fraction in the injection gas and to provide a method of evaluating whether it is worthwhile to add or retain a small amount of nC5 to the injection gas to improve miscibility with the reservoir fluid. Thus, more oil can be recovered and the added injection gas expense may perhaps be justified.
Reservoir Fluid Sampling Revisited—A Practical Perspective
Authors: Bon J. , Sarma H. K. , Rodrigues J. T. , Bon J. G.
Published: December 2007

PVT fluid properties are an integral part of determining the ultimate oil recovery and characterization of a reservoir, and are a vital tool in our attempts to enhance the reservoir's productive capability. However, as the experimental procedures to obtain these are time consuming and expensive, they are often based on analyses of a few reservoir fluid samples, which are then applied to the entire reservoir. Therefore, it is of utmost importance to ensure that representative samples are taken, as they are fundamental to the reliability and accuracy of a study.

Critical to the successful sampling of a reservoir fluid is the correct employment of sampling procedures and well conditioning prior to and during sampling. There are two general methods of sampling; surface and subsurface sampling. However, within these there exist different methods that can be more applicable to a particular type of reservoir fluid than to another. Further to this, well conditioning can differ depending on the type of reservoir fluid. Sampling methods for each reservoir type will be discussed with an emphasis on scenarios where difficulties arise, such as near critical reservoir fluids and saturated reservoirs. Methods including single-phase sampling and iso-kinetic sampling, which have been used increasingly in the last decade, will also be discussed with some detail as will preserving the representativeness of other components in the sample including asphaltenes, mercury and sulphur compounds.

The paper presents a discussion aimed at better understanding the methods available, concepts behind the methods, well conditioning and problems involved in obtaining representative fluid samples.
History Matching for Determination of Fracture Permeability and Capillary Pressure
Authors: Gang T. , Kelkar M.
Published: December 2007

For naturally fractured reservoirs, it is very difficult to quantify the future prediction without proper fracture properties and capillary pressure. Capillary pressure and fracture permeability can interact in a way which can produce non-unique results. For example, strong imbibition capillary curve with high fracture-matrix permeability contrast can behave similarly as weak imbibition capillary curve with low fracture-matrix permeability contrast. Evaluation of core data may provide us with some information about imbibition capillary pressure curves; however, quantification of fracture permeability is largely determined by matching the production data.

This paper presents an integrated approach to history matching of naturally fractured reservoirs by adjusting the fracture permeability of individual fractures and the water-oil capillary pressure curves. By matching production data by minimization of a weighted least squares objective function, we generate estimates of fracture permeability, and water-oil capillary pressure curves. All of implementations are incorporated into a commercial simulator (ECLIPSE) and iterated in the automatic history matching scheme. The adjoint method and an efficient direct solver were used to decrease CPU time for calculating the sensitivity coefficient matrix. A Middle East reservoir model was used to validate our method.
The Importance of Graphical Methods in Estimation of the Diffusion Coefficient of Gases in Bitumens and Heavy Oil
Authors: Sheikha H. , Pooladi-Darvish M. , Mehrotra A. K.
Published: December 2007

Graphical methods are important tools in estimation of the diffusion coefficient as well as identifying various stages involved in the ordinary diffusion. In this work, graphical methods were used for the estimation of diffusion coefficient of gases in highly-viscous oil-sands bitumens from isothermal, pressure-decay measurements. The approach involves modeling the rate of change in pressure with the diffusion equation for the liquid phase coupled with a mass balance equation for the gas phase. The inverse solution framework is utilized to arrive at graphical techniques for estimating the diffusion coefficient. An advantage of the proposed techniques is that the diffusion coefficient is estimated directly, i.e. without making it an adjustable parameter. The novelty of the proposed method is in its simplicity as well as its ability to isolate portions of the pressure-decay data affected by experimental fluctuations. The diffusion coefficients of CO2, CH4, and N2 in Athabasca bitumen at 75–90˚C and about 4 MPa were estimated and compared with literature values.
Near a Kilometer of Perforating Guns, in a 7½ Kilometer, Extended Reach Well - Coiled Tubing Shows its Mettle in New Zealand
Authors: Bartholomew P. , Portman L. , Frost R. , Nunn P. , Vause P. , Edmondson D. , Andrich L. , LaGrange T.
Published: December 2007

This paper details a coiled tubing perforating campaign conducted in New Zealand, during the first half of 2006.

Coiled tubing has been used for deploying perforating guns for many years now. The challenge with this type of work, is first designing a coiled tubing string which can push and pull long gun lengths along highly deviated wells. Secondly, a method of retrieving (and deploying) the guns against a high wellhead pressure is required. In this instance, down hole isolation valves could not be used. Instead, a pressure deployment system was utilized.

The length of perforating guns run during this campaign is extreme, but not unique1. The use of pressure deployment systems is also not unique2. The combination of these factors along with the facts that this is a very remote operation (with regard to oilfield manufacturing and supply), that much specialized equipment needed to be fabricated (in a market cycle where all equipment deliveries see long lead times), and that the operation must take place in a seismically active area, all combine to make this a very challenging project.

This paper lists observations taken from the project that may prove useful to future campaigns of a similar nature.
Significant Peculiarities Prediction of Condensate Production in Gas Condensate Fields
Authors: Brusilovsky Alexander I. , Nugayeva Alphiya N.
Published: December 2007

The paper is devoted to the prediction of the condensate content in a gas-condensate mixture during depletion, and the estimation of the condensate recovery factor. It is shown that the traditional approach to tackle this problem may result in both overestimated and considerably underestimated condensate production forecast.

Individual and combined influence of the formation temperature and dispersed hydrocarbon (HC) liquid on the variation of the C5+ content in the reservoir gas, and the condensate recovery factor for the depletion of the condensate gas cap are analyzed with examples of the Orenburg and Dulisma fields. It is proved that the traditional approach to predicting the presence of C5+ group in the formation gas by ignoring the presence of the dispersed hydrocarbon liquid (DHCL) in the reservoir can lead to overestimated condensate production rates. Particular influence of the anomalous low formation temperature on the retrograde condensation rate and the associated condensate recovery factor are analized.

Advanced methods for modeling multicomponent phase behavior are used to analyze the impact of the HC fluids properties on the expected C5+ content in the produced mixture, and on the condensate recovery factor for the depletion of near critical gas condensate reservoirs. It is shown that when dealing with such HC systems, the traditional approach to predicting the C5+ hydrocarbon content in the produced gas, based on differential condensation (constant volume depletion, CVD) studies, may result in significantly underestimated condensate production, and consequently its recovery factor.
A Novel Cased Hole Density-Neutron Log–Characteristics and Interpretation
Authors: Elkington P. A. S. , Pereira C. A. , Samworth J. R.
Published: December 2007

We have characterized the response of a compact 2¼-inch (57mm) diameter open-hole formation density logging tool for cased hole environments. Data are processed with an established open hole transform in which the casing effect appears as a simple attenuation term in the count rate domain, and variations in cement thickness are compensated using a classical dual-detector spine-and-ribs approach applied in the density domain. The combination of through-casing density and casing-corrected neutron porosity has been applied to the evaluation of by-passed pay and shallow gas, and to the evaluation of wells where open hole acquisition has not been feasible for operational, hole quality, or economic reasons. The tool-specific neutron porosity excavation effect has been characterized for gas-bearing sands.

Case history and model results suggest accurate formation densities are achievable for casing thicknesses up to about 0.35 inches (9mm) if cement is less than about 1 inch (25mm) thick, albeit with loss of precision relative to open hole. Formation sensitivity declines with increased cement thickness until practically all is lost for casing standoffs in excess of 1.5 inches (38mm). For modest thicknesses, however, cased hole density-neutron gas evaluation has advantages relative to the neutron-dipole sonic method; in particular it does not rely on good cement bond, it has generally superior spatial resolution, and (optionally) data can be acquired in memory mode on slickline in operating environments that do not favour conventional wireline units.
Design and Performance Evaluation of an Ultradeepwater Subsea Blowout Preventor Control System Using Shape Memory Alloy Actuators
Authors: Ma Ning , Hu Ziping , Samuel Robello , Ehlig-Economides Christine A. , Song Gangbing
Published: December 2007

As drilling moves to ultradeepwater, conventional blowout preventers (BOP) actuation technologies based on full or partial hydraulics are unable to meet the API standard for control system response times because of long hydraulic fluid communication path between an offshore platform and a BOP stack on the sea floor. Now that an ultradeepwater subsea blowout preventer (SSBOP) control system using shape memory alloy actuators has been demonstrated in the laboratory, several practical issues can be addressed.

The experimental device uses nitinol smart alloy material (SMA). It can be actuated by electrical heating, thereby replacing hydraulic actuation and hydraulic lines with electric cables. Alternatively, the SMA actuator system can be activated by chemical heating. With significantly fewer components, the SMA system will dramatically reduce total cost and will increase operation reliability. The new device can easily be retrofitted to existing conventional subsea control system thus enabling other methods to be used as a backup. Most importantly, the innovative all-electric BOP will provide a much faster response than its hydraulic counterpart and will improve safety for subsea drilling. The BOP actuator uses strands of SMA wires to achieve large force and large displacement in a remarkably small space. Experimental results demonstrate that the BOP can be activated and fully closed in less than 15 seconds.

This paper considers chemical and thermal energy sources as alternatives to electricity and ways to trigger an automatic mechanism. Additionally, a model is used to calculate the SMA length and diameter that will be required to provide sufficient force for different types and diameters of BOP rams (blind, pipe, or shear) or the annular BOP, and the energy requirements in each case. The model also addresses the range of pressures and temperatures that can be handled. Simple guidelines are presented along with practical field examples for different types of BOP hook ups.
Optimized Perforation—From Black Art to Engineering Software Tool
Authors: Bell M. R. G. , Davies J. B. , Simonian S.
Published: December 2007

While assisting production engineers in managing the perforating process, Shell recognized the need for an engineering software tool to guide and advise them. It needed to address selecting the optimum perforating system for given well and formation properties, and work at log resolution to eliminate problems experienced with existing packages that use input values averaged across the reservoir.

After consultation with staff engineers, the tool was created in Excel to test functionality and later transformed into a desktop application. It includes a perforating system database built from published API data. This is not ideal, since API Section I data are an unreliable predictor of performance into stressed rock, but this is the only published data allowing direct comparison between systems.

The tool calculates depth of fluid invasion, stress-corrected penetration, and crushed zone properties at log resolution. An inflow profile and IPR curves are then generated. The analysis can be repeated for multiple guns to compare relative performance; for example, to assess whether incremental production predicted for a superior system justifies additional expenditure.

The user can also test the sensitivity of inflow performance to perforating system performance and input assumptions. If system performance is critical, this may encourage laboratory tests under representative conditions to verify penetration and inflow.

Developing the tool highlighted fundamental shortcomings in the industry's understanding of perforation, such as: how the crushed zone is formed and removed; the role played by pressure dynamics; the sensitivity of penetration and tunnel quality to formation and system parameters; and, how jet perforators perform in targets other than sandstone. This lack of understanding has contributed to technology stagnation, sub-optimal well performance, poor decision making in the area of sandface completions, and undue belief in the value of allegedly performance-enhancing perforating services.

The work also brought into focus critical issues such as the industry's dependence on API Section I data - as a result of which we continue to be hoodwinked by ‘record breaking’ penetration performance into concrete targets – and the lack of performance metrics in poorly negotiated long - term perforating service contracts.

As a result, Shell has initiated research programs to build a better understanding of perforating phenomena - the results of which will feed back into the software, refining its capabilities and increasing the user's ability to design and simulate perforating operations-is driving the development of new performance benchmarks, and is rethinking the way perforating services are procured.
Fracture Face Skin Evolution during Cleanup
Authors: Gdanski R. , Fulton D. , Shen C.
Published: December 2007

There remains considerable debate on the impact of fracture face matrix damage on cleanup and productivity of gas wells. The impact of the Cinco-Ley fracture face skin factor has been studied extensively, but normally using single-phase flow examples. Two-phase flow examples are usually limited to the impact on long-term production. This paper uses a new two-phase flow simulator to demonstrate the impact of fracture face matrix damage on both fracture treatment cleanup and fracture face skin evolution during cleanup and subsequent production. The simulator was validated by comparison of calculated skins with pressure buildup simulations evaluated using a high-end, third-party, pressure transient analysis package.

The study has demonstrated that fracture face skin relative to gas flow can be calculated continually throughout a simulation of fracture treatment cleanup and production. It was found that at lower matrix permeabilities, and subsequent higher capillary pressure curves, the impact of water saturation in the damage zone becomes much more important. Specifically, the effective fracture face skin relative to gas can be several times higher than expected based on single-phase flow. Furthermore, the figures show that at lower matrix permeabilities, the time required to achieve a reasonable fracture face skin relative to gas flow can require considerable production time, on the order of several weeks, even for moderate damage factors. The results demonstrate that in tight gas reservoirs (~0.01 md and less) even a moderate amount of matrix damage in a fracture face can result in high fracture face skins and exceedingly long times for treatment cleanup. As such, it becomes very important to minimize fracture face matrix damage during tight gas fracturing treatments.
Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination
Authors: O'Keefe M. , Eriksen K. O. , Williams S. , Stensland D. , Vasques R.
Published: December 2007

A new generation of sampling technology is introduced which allows a Wireline Formation Tester to sample reservoir fluids in open-hole with levels of filtrate contamination that are below measurable limits, in many cases. Furthermore, the time required on station to cleanup before sampling is significantly reduced compared to conventional sampling methods.

Formation fluid sampling has always been adversely affected by mud filtrate contamination, which introduces errors into the laboratory analysis and requires analytical methods to back-calculate the measured properties to the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance, that replaces the need for sampling during Drill Stem Tests and provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves.

The application of this new focused sampling technology is presented using four case studies from wells drilled on the Norwegian Continental Shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate, and explores the different factors that affect performance of the focused sampling technique.

An important consequence of negligible contamination is the ability to accurately measure fluid properties in-situ. And reduced cleanup time allows for multiple zones to be scanned efficiently. Downhole Fluid Analysis (DFA) can thus be utilized to reveal reservoir architecture that is unable to be determined by traditional wireline logs.
An Integrated Wellbore Stability and Sand Production Prediction Study for a Multi-Field Gas Development
Authors: Wu B. , Mohamed Nulwhoffal Arselan , Tan C. P. , Sukahar Md Wakif , Hong Teh Yat , Viswanathan C. , Yee Hon Vai
Published: December 2007

This paper presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and time-dependent stabilities of extended reach wells, and 2) to assess sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: 1) in-situ stresses, including magnitude and orientation, and formation pressure, 2) mechanical and petrophysical properties of the formations transected by the wellbore, and 3) properties of drilling fluid and its interaction with shale formations. The likelihood of wellbore instability and sand production for the development wells was assessed using in-house developed wellbore stability and sand production prediction tools.

Mud weight stability profiles showing the variation of lower and upper bound mud weights with depth were developed for typical vertical wells. Critical mud weight contour plots which show the variation of lower and upper bound mud weights with wellbore azimuth and deviation angle for preventing mechanical wellbore instability were developed for various formations. In addition, a drilling fluid design methodology that can be used for quick and reliable determination of the optimum mud design (weight, type and chemistry) was developed for the fields.

Critical drawdown and critical reservoir pressure profiles for assessing sand production potential in the fields were established. Sand production was found not to be a major problem in the early stage of production. However, depletion in reservoir pressure and water-cut can significantly increase sand production risk.
A Multi-Component Dual-Porosity Model for Gas Reservoir Flow with Adsorption Behaviour
Authors: Lu M. , Connell L. D.
Published: December 2007

This study presents a modified dual-porosity model for multispecies gas flow with adsorption behaviour, which is formulated from an exact formal solution of a linear multicomponent gas diffusion process within a porous matrix block. Therefore, the coupling effects of mutual-diffusion are included in the representation. This new respresentation, in its first order form, exhibits to be a simple algebraic expression that is of an equivalent computational efficiency in comparison with the traditional Warren and Root. Yet, the mutual-diffusion effect is not present in the latter one.

A numerical algorithm is also developed for this model when the full form of it, which is of an integral form with history-dependency, is incorporated into a set of multi-phase and multi-species flow equations. A numerical example with the proposed model for a two-phase and three gas-species flow is performed in light of a parametric study, demonstrating that multi-component gas species interactions have significant influences on the flow profile. For instance, even if the off-diagonal diffusion coefficients are smaller by one order of magnitude in comparison to their diagonal counterparts, the resultant effect on model predictions can still be 10∼35%. Ignoring the diffusional interactions between the gas species, as is done with the Warren-Root, will introduce considerable deviations.
Methods for Real-Time and High-Resolution Formation Evaluation and Formation Testing of Thinly Bedded Reservoirs in Exploration Wells
Authors: Claverie M. , Aboel-Abbas S. , Mutiara C. S. , Harfoushian H. , Hansen S. , Leech R.
Published: December 2007

Thinly bedded reservoirs are increasingly a target of offshore exploration in the Malay Basin. These reservoirs exhibit heterolithic interbedding with vertical heterogeneity and a wide range of layer flow properties. This paper describes methods of real-time and high-resolution formation evaluation and formation testing used to characterize such reservoirs.

The formation evaluation of thinly bedded reservoirs has several objectives:

identify the layers that may contain hydrocarbons verify productivity and fluid types with formation testing and sampling calculate net pay thickness and uncertainty range.

The evaluation is complex because of bed geometry and lithology. The reservoir beds are often thinner than the resolution of the formation evaluation logs. They exhibit a silty lithology and fine grain texture, and require high quality borehole resistivity images to characterize their geometry. The exploration well offers the best chance to evaluate the prospect, but operational and economical constraints do not permit to core or test every potential reservoir. Therefore, a real-time evaluation must identify with certainty the prospects to test.

The sequence of real-time formation evaluation described here consists of the following steps.

Wellsite petrophysical analysis of: porosity volumes of clay, minerals and fluids permeability based on the combination of GR spectroscopy elemental yields, nuclear and sonic porosity, and array resistivity logs. Identification of thin beds, and computation of sand-count from an electrical borehole resistivity imager. Validation of the wellsite petrophysical analysis and the borehole image within two hours of recording the logs, and design of the wireline testing and sampling program.

A modular wireline formation tester is used to measure accurate in-situ pressures in potential reservoir rock and to establish fluid gradients and identify contacts. Additionally, local formation permeability is estimated from analyses of pretests, and is used to verify the productivity of thin beds identified by formation evaluation techniques.
A Case Study on the Numerical Simulation of Enhanced Coalbed Methane Recovery
Authors: Wei X. R. , Wang G. X. , Massarotto P. , Golding S. D.
Published: December 2007

A hypothetical pilot-scale project was studied to investigate the capabilities of existing coalbed methane (CBM) models in simulating the multicomponent gas sorption and diffusion in coalbeds for CO2-sequestration enhanced coalbed methane (ECBM) production. Further, the effects of coal properties, e.g. cleat permeability, porosity, cleat spacing, sorption isotherms of CH4 and CO2, and initial reservoir conditions, on CO2 breakthrough and methane recovery were investigated as well. The calculated results suggested that the multicomponent sorption equilibria described using IAS/Langmuir isotherm and extended Langmuir isotherm are quite different. The gas diffusion rate can not be accurately modeled using Warren & Root equation based on dual-porosity model (pseudo-steady state approach), which is so far the most popular approach used in CBM models to describe gas diffusion process. This indicates that a rigorous multicomponent gas diffusion model should be incorporated in CBM models to improve numerical simulation and prediction of CBM/ECBM production.