bluuebunny/crossref_metadata_2025 huggingface dataset:
Coupling EOS Compositional and Surfactant Models in a Fully Implicit Parallel Reservoir Simulator Using EACN Concept
Authors: Han C. , Delshad M. , Pope G. A. , Sepehrnoori K.
Published: December 2007

EOS compositional and surfactant models are coupled in a fully implicit parallel reservoir simulator using Equivalent Alkane Carbon Number (EACN) of oleic phase. The EACN of the oleic phase is computed using a mole-fraction-weighted carbon number for each component present in the oleic phase. Important microemulsion properties such as optimum salinity and optimum solubilization parameter as a function of EACN of oleic phase are implemented based on known correlations. The simulator developed is validated using our IMPEC chemical flooding simulator, UTCHEM. Case studies including a large-scale simulation emphasize that surfactant floods should be carefully modeled taking EACN of crude oil into consideration for more realistic and accurate oil recovery predictions.
World's First Gravel-Packed Uniform Inflow Control Completion
Authors: Augustine J. , Mathis S. , Nguyen H. , Gann C. , Gill J.
Published: December 2007

The Etame oil field, offshore Gabon, West Africa, has been producing since September 2002. The Etame oil reservoir is an oval-shaped, low-relief structure with a moderate aquifer drive. In order to maximize ultimate field recovery, the ET- 6H well was drilled with a horizontal lateral positioned to traverse the reservoir near the structural crest and to be within the Upper Gamba sandstone throughout its length. The Gamba sandstone averages 45 ft in thickness and overlies a significant angular unconformity. The subcropping Dentale- aged sandstones and interbedded shales below this unconformity have dips up to 12 degrees. The oil column of approximately 170 ft extends below this unconformity. Previous wells in the field were completed using open-hole horizontal gravel packs (OHGPs) and have experienced excellent sand control performance. However, OHGPs offer no protection against early water breakthrough. The Gamba sand averages 30% porosity with a permeability range of 1 to 3 darcies. The Dentale sands are much more variable, with porosities of 18-30% and a permeability range of 50-1000 md. Thus, if a portion of the lateral is situated immediately above a high permeability Dentale sand, the well will be at risk of early water breakthrough and subsequent reduced recovery if it is completed with a standard OHGP.

The operator gravel packed the ET-6H well and used a system that provides a near uniform inflow profile along the entire lateral length to protect against early water breakthrough. The gravel packing of inflow control devices presented some unique challenges due to their differences from standard sand control screens.

This paper describes the implementation of the world's first gravel packed uniform inflow control completion, including: inflow control device selection process, gravel pack design, data from the gravel pack operation, and resulting well performance.
Deepwater Completion Challenges Redefine Best Practices for Completion and Packer Fluid Selection
Authors: Javora P. H. , Stevens R. , Devine C. , Jeu S. , Simmons M. , Firmin G. , Poole G. , Franklin B. , Qu Q.
Published: December 2007

New materials used in deepwater production tubulars, and the increasingly complex and costly deepwater projects, demand greater attention to the design and selection of completion and packer fluids. This requires an integrated approach, from mud displacement through final sand control completion, in order to optimize fluid compatibility and effectiveness. In addition to standard compatibilities with reservoir rock and fluid, compatibilities of completion or packer fluid with control line, stimulation, and production fluids must be considered. Furthermore, compatibility of completion and packer fluids with production tubular metallurgies must be assured in order to prevent environmental cracking. The impact of the production environment on the potential formation of gas hydrates or crystallization of brine due to pressure, at the near- freezing mudline temperatures, must be understood for each of the wellbore fluids used during the completion process. For some projects, more than one completion or packer fluid choice is available, in which case each fluid should be evaluated to select the best ‘fit-for-purpose’ fluid.

This paper presents a new paradigm for testing and evaluating completion and packer fluids for selection in deepwater applications. Details for each test procedure and evaluation method are presented and include completion or packer fluid compatibilities with formation or synthetic formation water, control line fluids, and produced fluids. Core flow studies used to test fluid compatibility with the formation rock, and standard stress-cracking tests, conducted according to NACE guidelines, used to avoid the potential for environmentally assisted cracking of chrome production tubulars, are presented. Specialized evaluation methods to avoid the formation of gas hydrates and the pressure crystallization of completion and packer fluids are also presented. The best fit- for-purpose fluid was selected by following this new paradigm for a GOM deepwater project. Lessons learned are summarized in the paper.
Hybrid Simulation Using Neural Networks To Predict Drilling Hydraulics in Real Time
Authors: Fruhwirth R. K. , Thonhauser G. , Mathis W.
Published: December 2007

Prediction of hydraulic pressure for drilling operations is of essential interest, e.g. for well planning before and decision support while drilling. Until now numerous analytical models were developed but due to the lack of knowledge about important boundary conditions like in-situ mud rheology, well geometry and pipe roughness these models typically show limited success. The proposed method merges (existing) analytical models with knowledge based models utilizing drilling data. The model preference is thereby based on a range of statistical properties of the data. Neural networks are used to build a hybrid simulation trained and improved using historical data.

Prior to building such hybrid models it is important to get informative data sets. Automatic operations recognition enables an efficient selection of the drilling operations in all the recorded data. To remove noise and redundant information the data is filtered and re-sampled by sophisticated digital signal processing (DSP) techniques. The original sensor data from the past is not the only data source. Descriptive features are derived to achieve independence from specific well data, like drill string configuration, mud type and well trajectory.

For building the hybrid models novel neural network architecture is used in combination with parallel learning to avoid trapping into local error minima. In addition automatic network growing and highly sophisticated stopping criterions offer a robust and efficient estimation of the optimal network. Since a model for "normal" drilling is desired for automatic identification of "abnormal" drilling conditions in real time, data associated to abnormal drilling situations is excluded from network training. A sensitivity analysis provides a ranking about the impact of the particular model input onto the final results enabling us to remove unnecessary data and features.
Uses and Misuses of Pressure Data for Reserve Estimation
Authors: McLaughlin J. , Gouge B.
Published: December 2007

Pressure data can be a critical component of a reserve estimate. This data can come in many forms including: Pore pressure data captured prior to a well's completionEstimated pore pressure taken during completionDrawdown data collected during productionPressure buildup data collected with a bottomhole pressure gauge.

Each of these data sources requires its own analysis and quality check techniques. With the appropriate supporting geological and engineering data, pressure measurements and analysis of sufficient quality can potentially provide evidence for fluid contacts, reservoir continuity, rock properties, original hydrocarbons in place, and reservoir geometry.

Often the Securities and Exchange Commission (SEC) and of the Society of Petroleum Engineers / World Petroleum Congress (SPE/WPC) definition requirements for "certainty", "reasonable certainty", and "known accumulations" disqualify some pressure interpretation methods for particular reserve estimation uses. This paper highlights some of the common pressure analysis applications that are not recognized by one or both of the reserve standards. Also presented are some applications that have been sanctioned for select reserve estimation applications.

As can be expected for such a broad topic as pressure data, many issues are not black-and-white. In these cases, this paper outlines some of the critical concerns to be considered when evaluating a pressure analysis application for assigning reserves under SEC or SPE/WPC guidelines.
Capillary Wicking in Gas Wells
Authors: Mahadevan J. , Sharma M. M. , Yortsos Y. C.
Published: December 2007

Gas expansion near the wellbore during production causes the evaporation of connate water. When the reservoir permeability is low, capillarity is controlling, causing liquid movement to the near-wellbore region where drying rates are higher. In tight gas sands or in shale gas formations, where capillarity is high, the gas production itself can cause depletion of the water saturation below residual values, due to such evaporation.

In this work we present a study of the fundamental processes involved during the flow of a gas in a liquid-saturated porous medium. We have modeled evaporation by accounting for the capillary driven film flow or ‘wicking’ of saline liquid to the wellbore or the near-fracture region and the effect of gas expansion. It is shown that, for gas reservoirs with connate water saturation, large pressure drawdowns lead to a drying front that develops at the formation face and propagates into the reservoir. When pressure drops are lower, water rapidly redistributes due to capillarity-induced movement of liquid from high-to low-saturation regions. This phase redistribution causes higher drying rates near the wellbore.

The results show, for the first time, the effect of both capillarity-induced film flow and gas compressibility on the rate of drying in gas wells. The model can be used to help maximize gas production under conditions such as waterblocking by optimizing the operating conditions.Additionally it can be used to obtain a better understanding of the impact of capillarity on evaporation and consequent processes, such as salt precipitation.
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Options
Authors: Fuh G. -F. , Ramshaw I. , Freedman K. , Abdelmalek N. , Morita N.
Published: December 2007

Using two field case examples, this paper presents our current well construction and completion design analysis based on the following approach: (1) carry out detailed evaluation or determination of reservoir formation strength distribution using core testing, log data and drilling data analysis for rock strength estimate and its correlation with core testing results; (2) conduct a series of triaxial tests on selected reservoir core samples in the low to intermediate strength range for defining the stress-strain relationship (or material laws), rock failure and yield criteria, and other non-linear rock parameters required for numerical modeling analysis; (3) perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation. The types of completion design analyzed include cased hole completion using conventional perforations or stress-oriented perforations in inclined or high-angle well, openhole completion in high-angle or horizontal well, screen failure analysis in openhole completion, etc. In addition to investigating the mechanical response of the rock formations in each completion design, the model simulates both well drawdown and reservoir depletion effects on sand failure potential throughout the reservoir life. The results of such systematic study provide useful guidelines on well design and completion strategy for sand control or sand management in order to optimize well productivity. The two case examples presented in this paper highlight the use of this technique and approach. We have used this type of analysis and process for the well design in our business operations around the world with good success.

Based on our case example analyses and the specific rock failure characteristics as defined in the laboratory testing results and subsequent numerical simulations of sanding behavior, we are able to identify the most viable well construction and completion design for achieving a superior well deliverability and productivity for the long term, minimizing problems due to unintended solid influx and/or loss of well integrity over the reservoir life. The two field case examples in the North Sea as presented demonstrate and highlight the fundamental concept, methodology and the procedures for conducting the well design analysis through a series of computer simulations of various options for well completion schemes. The field example results will also show the effective use of rock failure characteristics by the engineers for the control of critical flowing bottom-hole pressure in relation to the reservoir drawdown and depletion to avoid premature sand failures during well production.
Preparing a Business Case for Technology Investment in Production Operations
Authors: Hite J. R. , Farid K. , Blanton M. L. , Gard F. , Crawley C. , Menda D. B.H. , Dotterer R. A. , Saputelli L. , Deaton D. F. , Sankaran S.
Published: December 2007

This paper describes the principles for preparing a convincing business case. The focus is on technology investments in production operations.

There seems to be wide-spread support in most large organizations for the implementation of new technology. The challenge is in speaking to decision makers in a clear and convincing manner. A good business case describes clearly what the investment is, what the risks are, and what the expected benefits are.
Analytical Solution for Injection-Falloff-Production Test
Authors: Chen Shi , Li Gaoming , Reynolds A. C.
Published: December 2007

A novel well-test for in situ estimation of relative per-meabilities was recently proposed. This test consists of three periods, (i) injection of water into an oil reservoir, (ii) a falloff test and (iii) a producing period. The pro-ducing period is critical as it yields production data that reflects changes in sandface mobility and is thus highly sensitive to the parameters used to model relative permeability curves. A major shortcoming of the data analysis procedure proposed in previous work was that it required a numerical reservoir simulator for matching pressure data. In this work, based on Buckley-Leverett theory and ideas from a front tracking method, we derive an approximate analytical solution for the pressure response during an injection/falloff/production test (IFPT) by applying on the Thompson-Reynolds steady-state theory. By matching data to the analytical solution by minimization of a weighted least squares objective function, we generate estimates of absolute permeability, relative permeabilities and the well skin factor. We show the method can be applied with either power law models or B-splines.
Factors Affecting Horizontal Well Gravel-Pack Efficiency
Authors: Ojo K. P. , Osisanya S. O. , Ayeni K. B.
Published: December 2007

Four major factors affecting horizontal well gravel pack were studied using a 3-D simulator developed for horizontal well gravel packing. The factors include settling effect, gravel concentration, injection rate, and carrier fluid viscosity. The gravel pack process was simulated and the effectiveness and pack efficiency of the gravel pack job is determined using the simulator. The effect of carrier fluid viscosity on gravel-pack efficiency was studied by varying the viscosity between 1 and 51 cp, injection rate between 1 and 4 barrel per minute, and gravel concentration between 0.50 and 4.0 pound mass per gallon. These three factors affect the settling factor of the gravel as it enters the horizontal section which subsequently affects the pack effciciency of the gravel pack process.
Maximizing Production Capacity Using Intelligent-Well Systems in a Deepwater, West-Africa Field
Authors: Goggin D. J. , Ovuede M. A. , Liu N. , Ozdogan U. , Coleman P. B. , Meinert D. P. , Nygard I. , Gontijo J.
Published: December 2007

Large, deepwater fields with a limited number of wells may require intelligent well systems to maximize production capacity under facility constraints. Agbami field, a highly-dipping reservoir with many producing zones and few wells, will use intelligent well systems to manage fluid fronts in a gravity-stable recovery scheme.

The reservoir has many producing zones with high-quality rock properties. Intelligent well systems, which consist of interval control valves (ICVs) and many sensors, will be used to monitor, analyze, and control (MAC) injection and production at the zonal level. Analysis of sensor data will allow operations to estimate well capacity and calculate actual flow rates. Decisions for operational control will be made based on the data analysis, the results of which will be used to optimize overall field performance and maximize financial returns.

In this study, a strategy was developed to maximize Agbami's full-field rate capacity in three production phases; ramp-up, plateau, and decline. Rate capacity response was investigated at the field, well, and zonal levels, including operational and reservoir uncertainties; e.g., injector plugging, well downtime, permeability variation, and fault-seal settings. Using a combination of scenario-testing and mitigation strategies, several key decisions were made, including the number and placement location of ICVs based on well type, range of production and injection rates, and zonal allocation.
Operating in the Shadow of a Megalopolis
Authors: Dudics D. D. , Arsenault L.
Published: December 2007

Webster's New College Dictionary defines a Megalopolis as: "A region composed of several large cities and their suburbs in sufficient close proximity to be considered a single urban complex". To say that Los Angeles and Long Beach, California make up a single urban complex would be making an understatement. Twelve-million people living eyeball-to-eyeball are less like an urban complex and more like an urban nightmare, especially when one is caught up in the morning or evening commute. Shear numbers aside, the region's weather, beaches and amenities still draw newcomers who want to live the LA lifestyle.

Within earshot of the beaches, marinas and pleasure boats in Long Beach Harbor the Thums Long Beach Company (THUMS) has produced oil for over forty years. A key to operating successfully in such an environmentally sensitive area has been the company's two-fold approach to managing stakeholder relations. First and foremost, focus on the community. Second, and almost as equally important, communicate, communicate and communicate.

Oil was first discovered in Long Beach Harbor in the 1930's. The vast Wilmington Oil Field (4th largest in the Continental U.S.) runs along the Southern California coast from just offshore Seal Beach to just under Redondo Beach, 12 miles to the north. Original oil in place is estimated to be 3.1 billion barrels. To date, almost a 1 billion barrels have been produced.
Improving the Quality of Production Data and Its Effect on Allocation Factor and Reserves Estimation
Authors: Ghaempanah B. , Mehdizadeh P. , Scott S. L.
Published: December 2007

It is usual for production and reservoir engineers to consider measured well test data as exact values. In practice well rate data has different levels of uncertainty. A more realistic decline analysis and reservoir simulation can be done if these uncertainties are taken into consideration. The Process Capability Index (PCI) method, developed for quality control management, has been used in this paper to establish a protocol to quantify the "quality of well test data" and calculate the corresponding level of uncertainty. To obtain the uncertainty level corresponding to a field with any number of wells, Monte Carlo Simulation (MCS) has been used. The MCS is a robust numerical method in calculating the combined level of uncertainty of multi-component systems. In this paper a field with different wells has been considered. Finding the appropriate test data distribution function for each well, the final level of uncertainty of the production has been obtained. Then the impact of the uncertainty in well test data on decline analysis has been expressed and monitized. We believe the type of analysis developed in this paper would be a useful tool to evaluate the cost/benefits of any new technology, such as multiphase metering, for improved production measurement quality.
Application of a New Data-Driven Processing Method to LWD and Wireline Dispersive Compressional and Shear Waveform Data
Authors: Zheng Y. , Huang X. , Tang X. , Patterson D. , Yin H.
Published: December 2007

A challenge for acoustic logging data processing, especially LWD (logging while drilling) data, is how to realistically handle the dispersion effects of the waveform data. Significant dispersion is often encountered in the LWD compressional wave data acquired in an unconsolidated slow formation and in the quadrupole shear wave data with a heavy drilling mud. In the presence of dispersion, formation slowness computed from the waveform data is generally higher than the true slowness value. Correction for the dispersion effect usually uses an idealized theoretical model that may not be adequate to handle the actual wave dispersion in the varying LWD environments. To accurately handle the dispersion effect, a new data-driven method has recently been developed. The process is based on the actual dispersion computed from the data. The dispersion data are also used for quality control of the computed wave slowness. This new method is applied to extract compressional and shear slowness from the dispersive LWD and wireline acoustic waveform data from several wells. The results show that the new method realistically accounts for the dispersion effect in the waveform data and obtains more accurate estimates of formation slowness.
Drilling and Testing of an HP/HT Deep Gas Prospect from an Existing Well: Case History of Kra Al Maru 3 Deepening
Authors: Al-Saeedi M. J. , Singh J. R. , Mahesh V. S. , Al-Ajmi H. S. , Mckinnell D.
Published: December 2007

Kra Al-Maru 3 (KM-3) is a deep vertical exploration well originally drilled to investigate the hydrocarbon potential of the Jurassic formations. Investigation of the open hole logs/cores indicated that there was limited porosity development in the Marrat zones of interest. Therefore an operational opportunity became available to deepen the well to explore the deeper Triassic horizons which had gas bearing potential.

The main challenges of this well were to design an extended casing program within the constraints of the present wellbore to allow for drilling/testing of the well with a wellhead rating of 20,000 psi whilst assuring the collection of maximum amount of useable data (cores, logs, rates, pressures and samples).

In order to meet these challenges a special casing design was employed, based on the experiences of other deep wells. Special HPHT cement additives were specified for the cementing of the deep liner strings. Application of turbine and slim hole motor technology was tried and a HPHT well test operation was planned including the use of a state of the art 20,000 psi surface test package.

During the well re-entry major complications were encountered due to high pressure profile, high mud weights, severe losses and well control situations. During the initial short term test the well produced gas, condensate/light oil along with highly saline water which caused salt plugging of tubing and surface lines. Plans are in hand to re-enter the well for long term test after solving the problem of salt plugging.

This paper will present a case history of the well including the planning, design process, implementation and lessons learned from the drilling and testing operations. These conclusions will then provide the basis for future optimization in the design of these types of wells.
Nature Had It Right After All!—Constructing a "Plant Root"-Like Drainage System With Multiple Branches and Uninhibited Communication With Pores and Natural Fractures
Authors: Moss P. , Portman L. , Rae P. , Di Lullo G.
Published: December 2007

If reservoirs engineers could drill wells, they would surely not drill a single, small diameter hole, with the walls of that hole damaged to the point they are initially impermeable! They would probably drill a hole with no damage to the walls, preferably with open fractures or wormholes emanating from that main hole. They would further likely construct more of a network of branches, mimicking the root structure of plants, evolved to efficiently drain nutrients from a soil reservoir.

The problem, of course, has been that the technology required to create such a drainage system has been commercially unavailable. This situation changed, in Venezuela, in late 2005.

This paper describes several wells where multiple, relatively short-length laterals were constructed, maintaining communication with the natural fracture network of the formation, imposing no damage. The paper details the target reservoir's properties and its history of poor production. The new production figures are contrasted to the historical field numbers.

The method used was to simply dissolve a system of short laterals. This was achieved by pumping hydrochloric acid though a specially designed jetting assembly, attached to the bottom of a 1 ½″ coiled tubing unit. This revolutionary method not only creates a "reservoir engineer's" hole, it does so using simple equipment at a low-cost. Further details on the equipment are provided in the paper.
Drilling Fluids in an HP/HT Reservoir: Experiences With Three Different Systems on the Kristin Field Development
Authors: Hansen S. A. , Breivik D. H. , Gjønnes M. , Svanes K. , Vujovic M. , Svela P. E. , Sørheim O. I.
Published: December 2007

Kristin is a HP/HT field developed on Haltenbanken offshore mid-Norway. The Kristin development consists of 4 templates with a total of 12 subsea wells. The inclination through the reservoir ranges from 28 to 85 degrees. The reservoir at approx. 4600mTVD (15092 ft) has an initial pore pressure corresponding to 1.96sg EMW (16,36 ppg) and a temperature of 172°C (342°F). With a water depth of approx. 360m (1181 ft), a MW of 2.05sg (17,11 ppg) is needed to be able to maintain a riser margin.

Three different drilling fluid systems have been used in the reservoir section: 1) Cs/K-COOH clear brine system. 2) Invert emulsion HP/HT OBM. 3) Invert emulsion HP/HT OBM with ultra fine weight particles.

Challenges such as ECD management, hole stability, formation damage, weight material sag and operating on subsea HP/HT wells during harsh winter conditions had to be addressed both in the planning and the operational phase.

In this paper the background for selection of the drilling fluid is briefly described and especially the rationale behind using three different systems. The paper highlights operational experiences to illustrate how the drilling fluid systems influenced and coped with the challenges of drilling subsea, high angle HP/HT wells.

The paper provides a discussion of the pros and cons of the different fluids systems. Finally the paper identifies some of the challenges that lie ahead as the production has started and the reservoir starts to deplete.
Storm-Safe Deepwater Drilling
Authors: Nguyen Chau , Thethi Ricky , Lim Frank
Published: December 2007

The recent hurricanes that battered the offshore facilities in the Gulf of Mexico have prompted many operators and drilling contractors to rethink the way their drilling risers are designed for disconnection and retrieval before the hurricane arrives.

When drilling in very deep water depths, retrieval of the drilling riser is time consuming and tedious; and in emergency situations like the imminent arrival of a hurricane, the drilling rigs risk not being able to recover the drilling risers in time before the evacuation of personnel or sailing for shelters, with potentially devastating consequences.

A solution to overcome this concern is to modify the existing drilling riser to make it disconnectable closer to the surface and leave the long riser string below (and subsea BOP) in a safe and freestanding mode to survive the storm.

This paper presents the feasibility of such a modification, and describes the simple buoyancy system and additional components required. The study also outlines hydrodynamic and structural analyses required to demonstrate integrity of the freestanding drilling riser.
Limitations to Storage Pressure in Finite Saline Aquifers and the Effect of CO2 Solubility on Storage Pressure
Authors: van der Meer L. G. H. , van Wees J. D.
Published: December 2007

CO2 storage in aquifers is an attractive option for reducing CO2 emissions into the atmosphere. The successful example of CO2 storage in the Sleipner injection project proves that large volumes of CO2 can be stored in a water-bearing subsurface formation. In general, most of the injected CO2 will displace water and will accumulate as free gas at the crest of the aquifer.

On the other hand, CO2 is also soluble in water. Therefore, the aquifer or depleted reservoir will eventually be saturated with CO2. The present paper explores various aspects of the solution process, based on numerical simulation studies for a Norwegian type of open aquifer storage location and other types of storage structures. The case studies indicate that only in the long term (> 1000 yrs), solubility may offer a storage mechanism for most of the CO2 stored in depleted fields. This is due to the accumulation of CO2 in the gas phase, which has a limited contact area with the water phase. However, if injection strategies focus on exposing the injected CO2 to as much "fresh water" as possible (i.e. through extended and dispersed migration paths) the amount of CO2 in the free gas phase can be reduced significantly and within a shorter time.

It is commonly believed that all CO2 will eventually disappear because it will dissolve in water. We agree with the fact that all CO2 will dissolve if there is enough water, but when a lot of material (CO2) is added to the system, this will affect fluid volumes and pressures in the total storage system. By studying a practical, real storage location, we try to find out some of the pressure effects of CO2 solubility on the total storage capacity of the selected storage site.
Software Agents—An Emergent Software Technology That Enables Us To Build More Dynamic, Adaptable, and Robust Systems
Authors: Landre E. , Ølmheim J. , Wærsland G. O. , Rønneberg H.
Published: December 2007

The oil and gas industry need to improve operational efficiency, and to address more demanding government issued requirements with respect to environmental safety in vulnerable areas such as the artic north. These requirements drive for new IT solutions, solutions not possible to implement using the more traditional approaches to software development.

These new solutions must be able to sense the environment, make decisions without human intervention, and involve humans when needed. In the latter situation the software can be used to prioritize problems that need human attention and assist the human in making better decisions with respect to the available information and situation at hand.

Software agents provide the capabilities needed to build the necessary IT systems, and they have during the last 15 years been applied successfully in safety critical systems such as military target prioritization [9] and space shuttle operation [10]. Less dramatic solutions involve optimization of air field runways and scheduling of transport capacity in terms of ships and vehicles.

To explore the capabilities of software agents, Statoil has implemented several demonstrators addressing problems in constraint-based planning and business process support.

In this paper we will present how software agents can be used to improve decisions in core oil industry processes such as drilling, production, processing and operation & maintenance. The main focus will be the on production, processing and operation & maintenance as these three processes can be directly supported by the same software agents. Drilling must be supported by another set of agents because drilling operations are conducted during a different phase of the development using different infrastructure.

An interesting observation from our own prototyping effort illustrated in figure 3 is that the three processes production, processing and operations & maintenance can be supported by less than 10 software agents in its initial outline. This is as expected, according to Dr. Ronnquist, and illustrates the power of software agents as a software design tool [11].
Gas-Injection Redistribution Revitalizes a Mature Volatile Oil Field: Cusiana Field Case Study
Authors: Soto L. , Penuela G. , Benavides I. , Martinez M. , Castiblanco I. , Chaves I.
Published: December 2007

Cusiana is a field of three stacked reservoirs (Mirador, Barco and Guadalupe) of volatile oil with a rich gas cap at the top. After a decade of gas re-injection at the crest of the main reservoir, Mirador, the fluid composition has changed as a result of production/injection. The static framework of this highly heterogeneous reservoir has changed too. For instance, minor faults that were proved to be seals at initial conditions are leaking and fractures that used to be passive have been reactivated today.

Initial miscible gas injection strategy in Mirador delivered so far an oil recovery factor (RF) of 50% with remaining oil in areas difficult to access such as an oil rim between the producers and a weak aquifer, poor quality rock layers, and bypassed between the producers and the gas injectors. In Barco and Guadalupe, initial water injection successfully provided pressure support but did not sweep oil as expected (RF= 25%).

A strategy was designed to recover additional oil by moving gas injection points to deeper formations, the flank of the structure, injecting at low flow rates from distributed injection points and maintaining a favorable voidage replacement. This strategy was based on a synergy among the three reservoirs, which allowed well conversions, rehabilitation of 9 shut-in wells to be injectors or producers and conversion of 10.5 km of water injection flowline, which expanded the gas injection network.

After 40% of the strategy implementation by the end of 2005, 1.8 MMSTB of incremental oil has been recovered, reducing the monthly field oil rate decline by half. This success has "boosted" the continuation of the gas injection redistribution strategy for 2006.

This paper describes the geological and reservoir engineering modeling that was performed to design the gas injection redistribution strategy in this mature field.
When Does a Longer Shut-In Lead to a Larger Radius of Investigation?
Authors: Ewens S. , Pooladi-Darvish M.
Published: December 2007

While the concept of radius of investigation is better understood for drawdown tests, its applicability to buildup tests is less certain. For example, a rule of thumb is that "one cannot see a particular feature in a buildup unless the radius of investigation during the preceding flow period has seen that feature". In this paper, we clearly illustrate that the radius of investigation of a buildup can be larger than that of its previous flow period.

Another common contention is that the radius of investigation of a buildup is limited by noise dominating the late time pressure behavior. Oliver1 and later Thompson and Reynolds2 defined the radius of investigation based on the distance from the well to the region of the reservoir which has the greatest impact on the pressure derivative. We have used this approach to calculate the derivative and show that the ratio of noise to the signal from the reservoir does not necessarily increase. We show that when data is sampled appropriately, the radius of investigation of a buildup can easily go beyond that of the preceding flow period, and clearly demonstrate when this may remain unaffected by noise.
Cement Shrinkage Measurement in Oilwell Cementing—A Comparative Study of Laboratory Methods and Procedures
Authors: Reddy B. R. , Xu Ying , Ravi Kris , Gray Dennis , Pattillo P. D.
Published: December 2007

Cement sheath shrinkage after placing the cement slurry in the annulus has been of concern in oilwell cementing because of the potential detrimental effects that shrinkage can have on long-term zonal isolation.

This paper compares several methods for measuring cement shrinkage under a variety of conditions including those downhole. Using the various methods, cement shrinkage in environments where the cement slurry is either closed to or open to external water sources was measured and the values were compared. The methods used for measurement under atmospheric conditions were based on API test apparatus (balloon and ring-mold) and flask methods currently used in field labs. Measurements under pressure and temperature were performed using the ring-mold method, in-house designed equipment, and newly available commercial equipment.

The values obtained by the different methods are discussed. Procedure modifications are proposed for measuring volume changes to cement slurries based on placement time, shear history, and gel-strength development.

The results presented in this work can be used to test shrinkage characteristics of cement slurries in the lab, under downhole conditions, and to select a cement system that is fit for purpose.
Qualifying Proppant Performance
Authors: Freeman E. R. , Anschutz D. A. , Renkes J. J. , Milton-Tayler D.
Published: December 2007

Qualifying proppant performance prior to a frac job, or simply verifying proppant performance after a frac job, can add significant value to propped fracture stimulations. Through a blend of established practices and new technology, data can be generated that will give an engineer insight into how specific proppants are designed to perform. This is without running expensive and time consuming conductivity and permeability tests on every job.

A primary objective is to establish representative, reliable and reproducible data via a sample collected from a large mass. American Petroleum Institute (API) Recommended Practices (RP) identifies three primary tenets: 1) representative sampling from a flowing stream, 2) standardized testing with calibrated equipment, and 3) sample retention for follow-up evaluation. Application of these practices ensures that proppant test data is valid (e.g. representative, reliable, and reproducible). Yet, these practices alone typically quantify quality but do not qualify proppant performance.1,2,3

Correlation of valid well-site proppant data with published information (literature, web-sites, or fracturing simulators) enables one to identify disparities. Any differences in part may be the result of mining anomalies, manufacturing defects, transportation abuse, and/or contamination. These can directly impact the delivered performance of your chosen proppant. Since proppant flow capacity or conductivity is a key measure of that performance, some empirical results have been assimilated for well-site and public data.

As a consumer, having information that describes the proppant at the well-site is important to deciding application and value. By compiling historical well-site proppant data one can set a minimum threshold of required properties or specification. This provides the opportunity to identify a greater range of proppants (e.g. substitutions) that meet reservoir, economic, and supply chain needs.

Lastly, this paper introduces new patent-pending technology that enables well-site proppant sampling and evaluation before the fracturing treatment. Having pre-frac data gives one the opportunity to make any necessary changes in fracture design and implementation to get the most from available proppant. It also provides for a detailed inspection of the well-site delivered proppant supply. For instance, one can isolate and sample each pneumatic trailer, monitor associated pneumatic discharge pressures, provide representative split samples for fracturing fluid compatibility testing, etc.

Case histories, onshore and offshore, support "qualifying proppant performance".
Drilling and Completions Waste-Management Strategy in Deepwater Angola
Authors: Klein R. J. , Walls A. H. , Page P. , Chambers B. , Gallagher R. , Burt D.
Published: December 2007

BP's recent exploration success in Angola is expected to result in a number of significant subsea developments in water depths ranging from 1200metres to in excess of 2000metres. Our understanding of the environmental impact of discharges associated with drilling and completions operations in deepwater Angola is immature at scale. Studies around single wells have been presented (Reference 1) but this type of work has not been considered for the development of a portfolio of subsea projects. A strategy and implementation plan has been developed by a multidisciplinary team to better understand the extent/impact of discharges and evaluate currently available and future waste management options, incorporating lessons learned from more mature deepwater operating areas where appropriate. This will enable informed decisions to be made on future implementation of best practicable waste management solutions.
Determination of 20-in. Conductor Setting Depth in Deepwater Wells in the Krishna-Godavari Basin Offshore India
Authors: Holasek Fred R. , Singh Raj K. , Shanker Shashi
Published: December 2007

Deep water well design and drilling is challenging due to the narrow separation between pore pressures and fracture pressure. Comparing the fundamentals of deep water well design to shallow water / onshore well design is dramatic. Once the pore pressures and fracture pressures have been modeled, the shallow water / onshore well design begin with choosing the desired casing size at total depth. Establishing the desired casing size at total depth for shallow water / onshore wells for the most part determines the casing points from total depth to surface. This is often referred to as the "Bottom-Up" well design.

On the contrary, deep water well design begins with the selection of the 20″ conductor depth. Once this depth has been selected, it determines subsequent casing points. This is commonly referred at the "Top-Down" well design. The deeper this string is set, the deeper the subsequent casing strings can be set. Extending this depth can eliminate entire casing strings. The challenge becomes to safely set the 20″ conductor as deep as possible.

A major deepwater drilling program has successfully drilled more than 19 wells in deep water in the Krishna-Godavari Basin. The setting depth of the 20″ casing has been extended using 3-D seismic, seal capacity analysis, shallow pore pressure prediction, shallow fracture pressure prediction and "pump and dump".

Once the 20″ conductor has been set, which is predominately in the very plastic Godavari clay, determining the maximum mud weight is also a challenge. The proper analysis will allow the next casing string to set deeper.

Although deep water well design in the Krishna-Godavari Basin should not be considered routine, the appropriate pre-drill analysis has significantly reduced the risks and costs of deep water drilling.
The Special Challenges of Killing a Blowout Caused by Illegal Oil Bunkering
Authors: Oudeman P.
Published: December 2007

Illegal oil bunkering, a euphemism for oil theft, has become a wide spread practice in the Niger Delta. Since these activities are not accompanied by the usual safety measures for oil production, dramatic accidents happen with consequences such as the loss of many lives and full-scale blowouts. A typical problem encountered in combating these blowouts is that no data are available on pressures, rates and fluids in the well prior to the blowout. Likewise records on well operations leading to the event are obviously missing. Hence the design of the kill will have to be based on historic data, on site observations and assumptions, which have to cover every possible scenario.

This case history describes how a blowout caused by illegal oil bunkering was killed successfully within the boundary condition of minimizing the impact of the blowout and the kill on the sensitive environment. The design of the kill, based on limited data and numerical simulations to determine the approach with the highest probability of success, planning and execution of the kill job will be discussed.

A post-kill analysis demonstrates that the design calculations accurately predicted the actual progress of the kill job. This increases confidence in these calculations for future application in emergency situations.
Improved Oil Recovery by Seismic Vibration: A Preliminary Assessment of Possible Mechanisms
Authors: Huh C.
Published: December 2007

Use of seismic vibration has been proposed as a low-cost IOR method, with reports of some successful field results. A key difficulty with the method is that its mechanism for oil recovery is not yet known, and accordingly, process performance prediction and reliable project design is so far not possible. In this study, a critical review of literature on the field and laboratory results and theoretical modeling work is first made. Employing a simple pore-level model and the well-established capillary number correlation, mobilization of waterflood residual oil by seismic vibration is shown to be unlikely, confirming earlier coreflood data.

A more likely mechanism for IOR is that vibration squeezes out the oil bypassed by earlier recovery methods, due to reservoir heterogeneity. While it is quite difficult to bring the injection fluids to the low-permeability zones in a highly heterogeneous reservoir, vibrational wave can transmit effectively through both high- and low-permeability zones. When a seismic vibration propagates through a heterogeneous reservoir, the pore pressure response in different permeability layers becomes different, generating a transient pressure difference and crossflow between the layers, potentially squeezing out oil from the low-permeability zones. The rock deformation and fluid flow equations are coupled to describe the effects of low-frequency oscillatory poroelastic deformation on crossflow. Improved oil recovery due to vibration-induced crossflow is approximately estimated. Our assessment that seismic vibration recovers only the oil bypassed due to reservoir heterogeneity may explain why the method's success is rather erratic, since accurate advance characterization of reservoir heterogeneity and the bypassed oil is inherently difficult. On positive side, seismic vibration may improve access of IOR chemical to low-permeability zones such as matrix portion of naturally fractured reservoirs, for better oil extraction from hard-to-access tight matrices.

Another important question that needs to be addressed is how to deliver vibrational energy effectively to a large volume of reservoir where the oil is. Fluid pressure oscillation damps down quickly in porous media and even the rock deformation wave attenuates significantly. One possible way is to transmit rock displacement wave continually so that its accumulation can form resonance in the reservoir. The resonance generation with the reservoir length scale as the resonance wavelength requires a very slow wave, and recent literature on the subject is discussed.