bluuebunny/crossref_metadata_2025 huggingface dataset:
A Diverless Subsea Drilling And Completion System
Authors: Page John
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The Petroleum Industry has ventured farther and farther offshore into deeper-and deeper waters exploring for needed hydrocarbons to meet increasing world energy demands and to replenish dwindling known oil and gas supplies. Since installation of their first subsea well completion system in 1962, Vetco has continued to engineer, develop, and manufacture subsea equipment to meet the increasing demands of this hostile environment. This paper describes a completely remote and diverless type of subsea drilling and completion system which has been developed, using field-proven principles and equipment. A 15-minute movie which records the actual installation of this subsea system in the Gulf of Mexico during 1976 is part of this presentation. The film, which was basically developed for training purposes, describes the general procedures and equipment used for this type of procedures and equipment used for this type of installation.

Introduction

Offshore oil and gas fields have, for many years, been produced from fixed platforms of various sizes which have been installed on the ocean floor and which become the base for directionally drilling of development wells. Land production equipment is used and the produced oil production equipment is used and the produced oil or gas is flowed or pumped to an offshore producing terminal or shore-based production producing terminal or shore-based production facility. The number of wells drilled and produced from a fixed platform varies considerably, depth and productivity being the criteria.

Until recently, water depths in which platforms were installed ranged from only a few feet to about 450 feet. Presently, however, with the technology available to the industry, these depths have been increased and platforms are being installed in deeper and deeper waters; one major company is planning to install a fixed platform in 1,000 feet of water off the Louisiana platform in 1,000 feet of water off the Louisiana coast. To date, however, the greatest depth at which a platform has been installed is 850 feet (in the Santa Barbara Channel).

During this and similar operations it became obvious that there was a depth at which it was technologically more difficult and economically improvident to consider fixed platforms, and other methods of production had to be investigated. Considerable time and effort was devoted to this problem; and, of the many ideas proposed, one of the more successful has been the single subsea wellhead completion system.
Evaluation And Control Of Sand Production In Gas Wells
Authors: Anand Jeevan
Published: December 2007

One of the major problems encountered in high deliverability gas wells is sand production from the formation and resultant erosion of subsurface and surface facilities. Because of extremely high velocities, even a small amount of sand for a very short duration can result in complete erosion of steel pipe at critical areas.

A testing program was carried out at Aliso Canyon Gas Storage Field in January-May 1976, with the following objectives:Quantify the steel erosion rate due to sand production for each well at different production rates.Project gas production rates at various reservoir pressures with an acceptable steel erosion rate.Evaluate different kinds of bottomhole completions with regard to their effectiveness in controlling sand production.

Specially designed steel probes were used in gas flow stream and their weight loss during the test was related to annual erosion loss of the steel pipes. Production rates were predicted based on constant sand face predicted based on constant sand face velocity at various reservoir pressures and found to be safe. A pressures and found to be safe. A critical review of the test data showed that bottomhole completions designed specifically to control sand production can substantially increase sand production can substantially increase sand free gas deliverability.

Introduction

Before an oil or gas field is acquired for gas storage purposes, testing is usually done to evaluate characteristics of the reservoir rock. Porosity, permeability and liquid saturation Porosity, permeability and liquid saturation are commonly determined, but sand production tendencies are rarely evaluated. production tendencies are rarely evaluated. This was the case when Southern California Gas Company acquired the Aliso Canyon Field for gas storage. Existing wells had been completed with both slotted liners and perforated casing.
Research on Hydrophobically Associating Water-Soluble Polymer Used for EOR
Authors: Yabin Niu , Jian Ouyang , Zhuoyan Zhu , Guijiang Wang , Guanghua Sun , Lijun Shi
Published: December 2007

On the base of molecular structure design, we have synthesized hydrophobically associating water-soluble polymers. The solution properties of hydrophobically associating water-soluble polymer as a function of electrolytes concentration temperature and shear rate have been investigated. The enhance in oil recovery obtained in core flow experiment with the polymers solution is higher. This polymer is developed for use under hostile reservoir conditions.
Study of Corrosion Control Effect of H2S Scavengers in Multiphase Systems
Authors: Tung Nguyen Phuong , Hung Pham Viet , Tien Hoang Dinh , Loi Cao My
Published: December 2007

Aggravated corrosion conditions caused by H2S in mixture of oil, brine and gas are responsible for some of the highest equipment failure rates in the petroleum industry. Thw sulfide scavengers HP1 and HP2 have been developed to protect well equipment and pipeline steel from sulfite cracking, electrochemical corrosion and corrosion fatigue. The desulfurisation efficiency and corrosion inhibition rate of scavengers in multiphase systems were measured in the laboratory. Their desulfurisation efficiency exceeded 90% and the corrosion inhibition rate was up to 98%.

Based on the obtained results, the scavengers HP1 and HP2 can be recommended for field test and field application as well.
Electromagnetic Propagation ... A New Dimension In Logging
Authors: Calvert Thomas J. , Wells Larry E.
Published: December 2007

One of the primary requirements of well logging is the ability to distinguish between oil and water. Resistivity/Conductivity and pulsed-neutron tools can do it if the water is fairly saline, and if its salinity is known. However, a method has long been needed that is less dependent upon knowledge of water salinity. Schlumberger's new Electromagnetic Propagation Tool measures the phase shift and attenuation of microwave-frequency energy propagated through the formation near the borehole. From these measurements, it is possible to derive values of porosity and water saturation that are practically porosity and water saturation that are practically independent of water salinity, except in ranges close to saturation. Notable is the fact that the new tool is most accurate in fresh waters, an area that has been troublesome. An experimental tool has been in the field for many months, running logs in eight states and a Canadian province. Field test results have exceeded expectations, and equipment is being built for commercial service. This paper gives the operating principles of the tool, describes the interpretation method that has been developed, and presents several field examples to illustrate the importance of this new logging measurement.
Using Neural Networks for Prediction of Formation Fracture Gradient
Authors: Sadiq T. , Nashawi I. S.
Published: December 2007

Accurate formation fracture gradient prediction is an essential part of well planning. Erroneous fracture gradient estimates may jeopardize the entire drilling operation and result in serious well problems, the least of which are lost circulation and kick leading to blowout. Accurate fracture gradient values play an important role in the selection of proper casing seats, prevention of lost circulation and planning of hydraulic fracturing for the purpose of increasing well productivity in zones of low permeability. Furthermore, a good knowledge of the fracture gradient is of great importance in areas where selective production and injection is practiced. In such areas the adjacent reservoirs consist of several sequences of dense and porous zones such that, if a fracture is initiated during drilling or stimulation, it can propagate and extend, establishing communication between hydrocarbon reservoirs and can extend to a nearby water-bearing formation.

Fracture gradient depends upon several factors including magnitude of overburden stress, formation stress within the area and formation pore pressure. Any prediction method should incorporate most of the above factors for a realistic prediction of the fracture gradient.

This paper presents an artificial neural network model that yields reasonably accurate values of the fracture gradient. The input training data are actual field data. The results obtained from the model are compared with those obtained from correlation. The comparison shows that the method is promising and under some circumstances it is superior to the available techniques.
Application of Hydraulic Fractures in Openhole Horizontal Wells
Authors: Ellis P. D. , Kniffin G. M. , Harkrider J. D.
Published: December 2007

This paper describes a process that has improved production, reduced costs, saved time, and dramatically improved the results of fracture stimulating low permeability horizontal wells. The use of both propped and acid fracture treatments will be described.

The process has been used for openhole completions aligned in the approximate direction of fracture propagation as well as for fractures transverse to the well bore. The technique has effectively eliminated well bore connectivity problems that had been observed in vertical completions and cased and cemented horizontal wells with transverse fractures.

The process has been used to increase production over 25 fold in a 30 year old field. It has also proven successful in a marginally economic field that had been completed using propped fractures in vertical wells.

The procedure employs a system of multiple, retrievable treating subs that are specifically tailored to a unique well bore configuration and allow treating the entire interval with a single stage. The treating subs are designed to distribute the treating fluid as desired along the length of the lateral. The process has been successfully used in over 100 wells and laterals in fields located in California, Illinois, New Mexico, Utah, and Texas.
Material-Balance Method for Production Rejuvenation With Horizontal Wells
Authors: Hsieh Frank S. , Kandel Philip S. , Vega Cecilia
Published: December 2007

Material balance evaluation can be conducted at every stage of reservoir development, including production rejuvenation using horizontal wells. Material balance evaluation for a reservoir with water influx usually begins with the calculation of water influx quantities using aquifer models (the aquifer model approach). The calculated influx quantities are substituted into material balance equations that are arranged in straight-line formats. Should a linear slope be found, the original-hydrocarbons-in-place is the y-intercept. The key to a successful evaluation using the aquifer model approach lies in the selection of a representative aquifer model. Selecting a representative aquifer model is difficult due to reservoir uncertainties such as rock properties, and the size, geometry, and continuity of the aquifer. Also, influx calculations using the aquifer model approach are time-consuming because they usually require a trial and error method of solution.

This paper presents a material balance equation in a form that allows for calculating water influx without the use of an aquifer model. This approach has many applications and is particularly useful for production rejuvenation projects, such as the drilling of horizontal wells.
Performance of Horizontal Wells in Gas-Condensate Reservoirs, Djebel Bissa Field, Algeria
Authors: Dehane A. , Algeria D. Tiab , Osisanya S. O.
Published: December 2007

Properties of gas-condensate reservoirs are particularly difficult to study due to the composition and phase changes of light components that occur during the reservoir depletion. At the first stage of their discovery, these reservoirs behave like gas reservoirs during depletion. Once the dew point pressure is reached at reservoir conditions of pressure and temperature a retrograde condensation phase develops in the reservoir. Liquid condensation in the formation can result in severe loss of well deliverability and therefore of gas and condensate recovery, which will certainly lead to a loss of income.

In this study, the performance of horizontal wells and vertical wells in gas condensate reservoirs is investigated under various depletion schemes. The expected low drawdown pressure for horizontal well, compared to vertical well for the same flow rate, considerably reduces retrograde condensation. A reservoir simulator is used to compare liquid saturation profiles for horizontal and vertical wells in gas condensate reservoirs. The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery were also studied. Another factor investigated in this study is the effect of drilling a horizontal well in a gas condensate reservoir that has already been developed by vertical wells.

To illustrate the productivity increase due to the use of horizontal wells in gas condensate reservoirs, Djebel Bissa field (Figs. 1 and 2) data are presented and discussed using a compositional single well model (VIP simulator). The main results of this investigation are as follows: A smaller pressure drawdown for a horizontal well compared to that of a vertical well, eliminates or reduces liquid condensation in the reservoir.

Layers with higher capacity (kh) values contain the most liquid accumulations.
A Numerical Model Coupling Reservoir and Horizontal Well Flow Dynamics: Transient Behavior of Single-Phase Liquid and Gas Flow
Authors: Vicente R. , Sarica C. , Ertekin T.
Published: December 2007

A fully implicit, three-dimensional simulator with local refinement around the wellbore is developed to solve reservoir and horizontal well flow equations simultaneously, for single-phase liquid and gas cases. The model consists of conservation of mass and Darcy’s law in the reservoir, and mass and momentum conservation in the wellbore for isothermal conditions. The coupling requeriments are satisfied by preserving the continuity of pressure and mass balance at the sandface. The proposed simulator is tested against and verified with the results obtained from a commercial code ECLIPSE-100™, and available public domain simulators and semi-analytical models.

The model can be used to simulate the transient pressure and flow rate behavior of both the reservoir and the horizontal wellbore. Traditional decoupling of the wellbore transients from the reservoir transients does not capture the horizontal well pressure and flow rate transients at early times since the interaction between the reservoir and wellbore is inherently neglected. Simulation runs with the proposed model reveal the actual characteristics of horizontal wellbore storage and unloading. The effects of permeability, formation thickness, well length, and fluid compressibility are also studied.
Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs
Authors: McLellan P. J. , Hawkes C. D. , Read R. S.
Published: December 2007

Sand production and the sand control technique selected to mitigate or eliminate it can have a critical influence on the performance of horizontal wells in gas storage reservoirs. A completion that provides adequate sand control is usually required, but an overly conservative completion design can have an unnecessary, negative consequence on gas well productivity and injectivity. The selection of the appropriate sand control design depends on the characteristics of the reservoir formation, the in-situ stress state, the maximum and minimum values of the reservoir pressure during gas storage operations, the drawdown pressure, the near-well fluid saturations, the well trajectory and the capacity for handling sand in the well tubulars and surface facilities.

This paper reviews the principal causes of sand production from borehole and perforation collapse, and demonstrates the application of commercial software programs for assessing sand production risks. The influence of formation damage, compressible and non-Darcy gas flow effects, reservoir pressure changes and rock strength reduction due to cyclic loading will be illustrated. Additional risks, such as exceeding the fracture breakdown pressure in the reservoir during injection, or collapsing weak, interbedded shale strata that are locally penetrated by the horizontal well, are also described. Numerical geomechanical modelling techniques suitable for more complex material behaviour and fluid flow phenomena are also described, as well as a novel procedure for estimating initial produced sand volumes.

Several field examples are presented, illustrating results for reservoirs ranging from relatively strong rocks, in which no sand control is required, to poorly cemented sandstones which require gravel-packed or screened completions.
Theory And Applications Of The Borehole Audio Tracer Survey
Authors: Britt E.L.
Published: December 2007

The Borehole Audio Tracer Survey (BATS or sound survey) is a new surveying device which can be used to locate and quantify fluid flow outside of casing. Additionally the sound* logger can be utilized as a flowmeter (without moving parts) to measure fluid flowing past the tool.

Part I illustrates use of the BATS log to locate and evaluate the quantity of fluid flow outside of casing. It is demonstrated that an index of flow magnitude can be determined and, as a result, a monetary value can be placed on this lost production.

Part II demonstrates the use of the BATS log to determine the relative flow rate of individual perforations in limited entry completion, where mass flow rate through the perforation is sufficient to produce turbulent flow. An additional technique for evaluating perforated zones (e.g. 4 per ft., etc.) is also shown.

Part III demonstrates use of the BATS device as a downhole flowmeter having no moving parts. It is shown that the BATS device, unlike mechanical flowmeters, can, under favorable circumstances, identify the type of fluid flowing (e.g. liquid, liquid-gas, or foam) as well as the flow rate.

Introduction

Since the Borehole Audio Tracer Survey is a new log to most interpretors, a description of the equipment, logging technique, and a brief theoretical explanation will be given. Additionally, two required corrections to observed log values will be explained.

Equipment - The downhole tool is 1 11/16" in diameter and 48" long with a 15,000 psi and 350 deg. F temperature rating. It can be run in conjunction with a temperature device to provide sequential surveys on a single trip in the hole. A very useful combination is the temperature and sound logger both recorded under shut-in and flowing conditions.

The downhole tool is simply a very sensitive microphone with a downhole amplifier. The transducer is designed to respond to sound which originates in any direction around the well and therefore has no directional properties.
Upgrading Athabasca Tar Sand Using Toe-to-Heel Air Injection
Authors: Xia T. X. , Greaves M.
Published: December 2007

The unique operation of the THAI process – Toe-to-Heel Air Injection, enables very high oil recovery and substantial in-situ upgrading. Both thermal upgrading (non-catalytic) and also catalytic upgrading, in which a catalyst is emplaced along the horizontal producer well, were investigated. 3-D physical model experiments were conducted on virgin Athabasca Tar Sand bitumen to investigate dry and wet combustion performance. These results were compared against those from a steamflood test, which was also followed by air injection. Excellent ignition and very stable combustion propagation was achieved using Athabasca Tar Sand. Thermal upgrading achieved nearly 10 API points increase. Additional upgrading was achieved using an in situ catalyst. The main limitation of using steam is that a very large fraction of the oil remains immobile. This residual oil can only be ‘unlocked’ by thermal cracking at high temperature (>500°C), as in THAI. THAI has the extra advantage that some hydrogen is generated in situ, providing further significant upgrading via hydroconversion. There are also substantial environmental benefits because of the large reductions in sulphur and heavy metals in the produced oil. Furthermore, oil is produced without ‘displacement delay’, immediately ahead of the combustion front. The Oil recovery using THAI was greater than 75% OOIP.
Gel Water Shutoff in Fractured or Faulted Horizontal Wells
Authors: Lane R. H. , Seright R. S.
Published: December 2007

Advancement in design and implementation of polymer gel water shutoff treatments in horizontal wells that penetrate fractures or faults have come from empirical improvements in the field and synergism between monitored field treatments and independent laboratory research. One case history will be detailed, followed by a summary of several other treatments.

Simple calculations can give at least a rudimentary indication of the width of the fracture or fault that causes excess water production. Using laboratory data coupled with field data collected before, during, and after gel injection, the calculations can also give an indication of how far the gel has actually penetrated into the fracture. Our analyses reveal critical measurements that should be made during field applications and where additional laboratory work is needed to aid in the design of field applications.
Development of a Single-Trip Coiled Tubing Sidetracking System
Authors: Grigor C. , Seale R. A.
Published: December 2007

Advancements in sidetracking and re-entry operations have progressed greatly over the past decade. However, these advancements have been predominantly in rotary applications. Milling systems for coiled tubing (CT) operations have evolved much slower. Size limitations have played a major role in the technology transfer from rotary applications. Currently multiple trips are required to successfully complete window milling operations.

Over the last 18 months a single trip CT sidetracking system has been developed that optimizes the efficiencies of the bottom hole assembly and the whipstock in CT sidetracking operations. This paper will discuss the bottom hole assembly analysis used to develop a specialized whipstock and mills for coiled tubing operations with the limited available power from smaller downhole motors.

Results of conventional one trip rotary systems will be compared to the new design in yard testing. These results will be followed by an analysis of each of the first six field trials performed utilizing the new system in vertical and horizontal applications.
An Investigation of ASTM Type I Cement for Oilwell Application in the Appalachian and Michigan Basins
Authors: Myers Roger R.
Published: December 2007

Cement manufacturers in the Appalachian and Michigan Basins stopped making API Class A cement years ago. Today, the pumping service industry provides its customers with Type I cement manufactured to ASTM C150-97 specifications. Many operators in these producing basins are unaware of this change and its implications for a quality cement job.

Much has been written about the characterization of Class H and other oilwell cements. For example, Polkowski concluded that the cement thickening time is directly related to Blaine Fineness and the average size of the C3S crystals and fluid loss control is a function of particle size distribution.1 Nelson traced the variability in oilwell cement back to the production plant, stating portland cement behavior can be linked to several production parameters including kiln temperature, raw materials processing and grinding. 2

It is the intent of this paper to educate the reader about the characteristics of ASTM C150-97 Type I cement being pumped in the Appalachian and Michigan Basins today. Cement from six different cement plants was analyzed using cement microscopy and chemical analysis. Typical cement laboratory tests were run to get a comparison of thickening time, compressive strength development and rheology using normal water/cement ratios.
Effects of Proppant Pack Concentration and Polymer Residue on Appalachian Stimulations
Authors: Mack David J.
Published: December 2007

The purpose of a hydraulic fracturing treatment is to provide a continuous path to the wellbore for hydrocarbon flow. The conductivity of this path has been shown to be effected by many factors including proppant size and physical properties, proppant fracture face concentration, closure pressure on the proppant and proppant pack damage. However, these studies have tended to investigate higher concentrations, typically in the range of 2 lbm/ft2 at closure pressures greater than 1,500 psi and temperatures in excess of 125° F. These criteria are generally outside the conditions experienced in typical Appalachian Basin applications.

This study investigates fracture face proppant concentrations less than 1.25 lbm/ft2, closure pressures less than 1,500 psi and temperatures below 125° F. In addition, the effects of polymer residue (actually polymer recovery) on low concentration proppant packs will be presented. The modified conductivity values are used in a production simulator to show the productivity effects exhibited by polymer residue in low fracture face proppant concentration wells.
Improving Gas Storage Development Planning Through Simulation-Optimization
Authors: Johnson Virginia M. , Ammer James R. , Trick Mona D.
Published: December 2007

This is the first of two papers describing the application of simulator-optimization methods to a natural gas storage field development planning problem. The results presented here illustrate the large gains in cost-effectiveness that can be made by employing the reservoir simulator as the foundation for a wide-ranging search for solutions to management problems. The current paper illustrates the application of these techniques given a deterministic view of the reservoir. A future paper will illustrate adaptations needed to accommodate uncertainties regarding reservoir properties.
Applying High-Resolution Numerical Schemes in Reservoirs Described by Complex Corner-Point Grids
Authors: Sammon Peter H. , Kurihara Masanori , Jialing Liang
Published: December 2007

Higher order numerical schemes are necessary to get good front resolution when modelling reservoirs using practical block sizes. Methods for such schemes presented to date have focussed on situations where the grids are somewhat regular. To be useful, implementations are required that can apply in situations when the gridding is complex, such as when corner point grids are involved that have non-regular cells, grid refinements are used, and when faults exist. This work discusses the implementation of higher order accurate methods in a corner point setting when refinements and faulting are present, and includes a discussion of how to maintain numerical stability. The implementation is carried out in an equation of state-based fully compositional reservoir simulator that uses complex corner point grids with faulting and refinements, thereby making higher order methods available for field scale reservoir modelling.

The numerical schemes use two point flux calculations and can be up to second order accurate in space in smooth regions, the latter being regions where the various component, phase saturation and pressure distributions (and hence phase velocities) are smoothly varying. A Total Variation Diminishing (TVD) flux limiter is required to maintain numerical stability. Such limiters are applied to the inter-cell flows in each component's mass balance equation to control throughput and to ensure overall stability of the resulting numerical scheme. The application of flux limiters also guarantees that the computed properties remain within their physical ranges. TVD limiters must be applied carefully when complex grids are encountered as cells have varying dimensions and can be partially contacted by neighbouring grid cells on several faces. Special consideration needs to be given to how the limiters are to be evaluated in these situations. This usage extends TVD technology beyond what has already been done in reservoir simulation, and makes its use practical for complicated field scale models.

The results of several simulations are demonstrated. In particular, the ability of the techniques to better resolve sharp fronts can be seen. This leads to a more accurate prediction of overall fluid movements, including fluid contamination and mixing, breakthrough timing, and front and/or fluid bank movement in the reservoir. A more precise evaluation of ultimate recovery for the reservoir is obtained, which leads to the opportunity to improve overall recovery.

The techniques described here can greatly enhance the accuracy of compositional reservoir simulation, and it is shown how these capabilities can be brought to the realm of field scale modelling with complex corner point grids.
Prediction of Oil Production With Confidence Intervals
Authors: Glimm James , Hou Shuling , Lee Yoon-ha , Sharp David , Ye Kenny
Published: December 2007

We present a prediction methodology for reservoir oil production rates which assesses uncertainty and yields confidence intervals associated with its prediction. The methodology combines new developments in the traditional areas of upscaling and history matching with a new theory for numerical solution errors and with Bayesian inference. We present recent results of coworkers and ourselves.
History Matching of Three-Phase Flow Production Data
Authors: Li Ruijian , Reynolds A. C. , Oliver D. S.
Published: December 2007

Adjoint equations for three-dimensional, three-phase flow problems are developed and implemented to calculate the sensitivity of production data to permeability fields and well skin factors. Typically, the development of adjoint equations is rather tedious, but the formulation given here makes the development and numerical solution of adjoint equations straightforward. The procedure for calculating sensitivity coefficients is coupled with a fully-implicit finite-difference simulator to develop an automatic history matching procedure. Even if one does not wish to fully automate history matching, sensitivity coefficients are useful for understanding the physics that control three-dimensional multiphase flow and the influence of local reservoir properties on production data. Procedures to estimate the value of particular types of data (pressure, producing gas-oil ratio and water-oil ratio) for reducing the uncertainty in estimates of reservoir properties are applied and discussed.
Applications of Streamline Simulations to Reservoir Studies
Authors: Samier P. , Quettier L. , Thiele M.
Published: December 2007

Computer models of oil reservoirs have become increasingly more complex in order to represent geological reality and its impact on fluid flow. Memory and CPU time limitations by finite difference/volume simulators force a coarser resolution of reservoirs models through upscaling.

Upscaling can lead to significant difficulties in reservoirs studies: (1) while the fine-scale geological model is build from petrophysical, log, and seismic data, its dynamic behaviour is never checked. As a result, a coarse-scale reservoir study can be linked to a fine-scale geological model but the two might be inconsistent in their dynamic behaviour. (2) Conversely, the upscaled model cannot be properly tested since the flow and production behaviour at the fine-scale level is not available. There is no reference solution for guiding important decisions for building a consistent upscaled model. (3) A large number of sector models are required in designing optimal well patterns.

Streamlines simulation is now an attractive alternative to overcome some of these drawbacks since it offers substantial computational efficiency while minimising numerical diffusion and grid orientation effects. It allows the integration of fine-scale geological models into the reservoir engineering workflow.

In this paper, we demonstrate the usefulness and efficiency of a streamline simulator (3DSL5) in the reservoir engineering workflow. We evaluate its speed, memory requirements and scalability using tracer and black oil test data sets on an SGI Origin 2000 (250 MHz MIPS). Our data are based on real fields and range from 200000 to 7 millions cells with cells as small as 30x30x0;5 meters. We examine problems with pre- and post-processing of large data sets and visualising such simulations. Streamlines allowed us to check the validity of a large geological model and to optimise wells patterns with more than 30 producers and injectors. Application of streamlines to the 10th SPE comparative solution project is also discussed.

We demonstrate how streamline-based simulation has matured from a research tool to an industrial application providing real benefits to engineers as a complementary tool to existing conventional simulation technology based on finite volumes.
Reservoir Simulation Applied to Production Operations
Authors: Briens F. , Chua H. T.
Published: December 2007

Reservoir simulation is traditionally used for reservoir management purpose, in an office environment. Reservoir simulation studies have often a long-term scope and require a significant amount of time to reach completion, generally several weeks. Additionally, traditional reservoir simulators require a considerable amount of training to become proficient in their use. Hence, reservoir simulation usually demands a full-time effort. For these reasons, reservoir simulation is a tool that has found little practical application in production operations and it is extremely rare to see it, for instance, being used at the well site. However, this is now changing with the availability of powerful portable computers and appropriate reservoir simulation software, which can make reservoir simulation an effective tool for decision-making in day-to-day production operations. This paper demonstrates with a number of case histories the variety of applications that reservoir simulation can have in a production environment and the added value it can generate.
Semi-Analytical Modeling of the Performance of Intelligent Well Completions
Authors: Valvatne P. H. , Durlofsky L. J. , Aziz K.
Published: December 2007

Complex well configurations coupled with intelligent completions offer great potential for the efficient production of oil reservoirs. One application of this technology is the use of surface adjustable downhole chokes. This allows wells to be divided into separate inflow zones, with each zone produced under a different pressure drawdown, but with production commingled. Chokes can be set to provide a more uniform inflow profile, which acts to delay the breakthrough of water and gas. The practical benefits of this technology have been demonstrated in several North Sea installations.

Despite the large technical and economic risks associated with these complex wells, little work has been presented on the detailed modeling of their performance. While it is possible to apply existing finite difference reservoir simulators, such models can be time consuming to build and the accuracy of the results depends on the grid and the well model. Here, we apply semi-analytical solution methods (based on Green’s functions), appropriate for modeling the performance of non-conventional wells operating under single phase flow conditions, to these complex well configurations. The approach entails a fully coupled nonlinear formulation that accounts for pressure drops in the annulus, tubing and downhole chokes.

Numerical results for a variety of cases are presented. The high degree of accuracy of the semi-analytical approach is first demonstrated through comparison to results from established methods for model problems. Then, using a geostatistical description of a highly heterogeneous fluvial reservoir, we demonstrate how the method can be used to model the performance of wells with intelligent completions. We show how the technique can be applied to determine downhole choke settings that provide optimal inflow profiles.
Use of Parallel Compositional Simulation to Investigate Productivity Improvement Options for a Retrograde-Gas-Condensate Field: A Case Study
Authors: Jutila H. A , Logmo-Ngog A. B. , Sarkar R. , Killough J. E. , Ross F. C.
Published: December 2007

This multi-disciplinary study involved the use of parallel simulation using the same grid size as the geological model. Various production technology options for the remaining wells in a field development were investigated and the benefits of gas cycling were examined. A geological model covering an area of 40 km2 was simulated using two approaches; one using 3 levels of nested LGR's and the other using an areal upscaling, both had nearly the same number of active grid cells. The 12-component Equation-of-State ("EoS") was substituted by 5-component to optimise the run speed of the simulation, 12-component was used for investigating gas cycling. The final engineering model had 320,000 active cells and completed 1.5-year history-matching runs in 1 hr 27 min using 16 parallel 400MHz processors with 1GB RAM each.

Both methods worked well and the history was matched with minor changes to the geological model. The primary match parameters were the relative permeability curves since relative permeabilities from special core analysis at reservoir conditions were not available. Correlations from the literature were used for the original relative permeability curves. These were modified to capture the effects of near-well velocity stripping by ‘straightening’ the curves and moving the end points. Through a combination of local grid refinement (LGR) and relative permeability modifications, the effects of the condensate dropout near wellbore and the transient effects were captured. These effects reduce the wells' productivity by 40% in the first weeks of production.

In the prediction phase the full field model was used to examine, holistically, the effects and interaction of various options chosen by analytical screening. The main solutions compared were high angle (near horizontal) reservoir penetrations and hydraulically fractured wells. Hydraulic fractures were modelled using LGR to capture the behaviour of the condensate in the fractures. The high angle wells were surrounded by LGR. A large number of prediction cases were run, optimising the development scenario using stochastically derived drilling schedules. Considerations of capital allocation led to the final recommendation from the group of optimal solutions.
Physically Based Higher Order Godunov Schemes for Compositional Simulation
Authors: Thiele Marco R. , Edwards Michael G.
Published: December 2007

Previous studies of higher order schemes for compositional reservoir simulation have mainly involved the use of spatially accurate methods. Our compositional computations in IMPES mode with spatially accurate TVD schemes show that for practical time step sizes the method can introduce significant oscillations.

In this paper, a novel scheme is introduced that is higher order in space and time. Higher order values of the variables of the system are derived at cell faces and are constrained to be monotonicity preserving. The compositional flux is then composed from the cell face variables to produce a locally conservative scheme that is Total Variation Diminishing (TVD) for linear advection and is a higher order Godunov scheme in the case of a non-linear conservation law.

Four component (CH4/C3/C6/C16) and six component (C02/CH4/C4/C10/C14/C20) examples are presented that demonstrate the behavior of the new scheme for complex compositional simulation. The new scheme produces high resolution results at a fraction of the cost of single point upstream (SPU) weighting. One-dimensional computations show that 1000 grid blocks are sufficient for the higher order scheme to approximate 20,000 single-point upstream (SPU) reference solutions leading to significant speed-ups. Our new method permits larger time steps than TVD schemes that are only spatially accurate and is consequently more robust and less CPU intensive than a spatially accurate scheme.
Gravity Drainage Performance of Depletion-Type Reservoirs
Authors: Matthews C.S. , Lefkovits H.C.
Published: December 2007

The performance of depletion-type reservoirs at the stage in which the gas is at such low pressure that gravity is essentially the sole driving force has been investigated both theoretically and by use of scaled models. A simple theory is developed which completely explains the scaled model experiments. It also agrees with some field data.

Introduction

This investigation was undertaken to determine a method for prediction of performance of reservoirs where gravity is the sole driving agent. Depletion-type reservoirs fall into this category after the pressure has fallen to some low value. Some examples of this type are found at Healdton, Okla; Oklahoma City; Midway-Sunset, Calif.; and East Coalinga, Calif. In the past, predictions of behavior of such reservoirs have been based on empirical extrapolation of the rate of production to the economic limit. Difficulties arise when new wells are drilled in the field or when production is artificially curtailed, since in such cases the decline rate of individual wells or leases changes and no clear trend can be detected. It was hoped that the present study would lead to improved methods for evaluation of such reservoirs.

The study was initiated by building a scaled model for a particular field and by running a number of experiments on this model, Later a simple theory was developed which explained the laboratory results completely.
Numerical Modeling of Aquifer Disposal of CO2
Authors: Pruess Karsten , Xu Tianfu , Apps John , Garcia Julio
Published: December 2007

Disposal of CO2 from stationary sources (fossil-fired power plants) into brackish (saline) aquifers has been suggested as a possible means for reducing emissions of greenhouse gases into the atmosphere. Injection of CO2 into such aquifers would be carried out at supercritical conditions, and would give rise to the evolution of a two-phase fluid system, in which most of the injected CO2 will reside in a dense supercritical gas phase, while also dissolving partially into the aqueous phase, and reacting with native minerals. This paper presents scoping studies of the amounts of CO2 that can be trapped into the various phases (gas, aqueous, and solid) for a range of conditions that may be encountered in typical disposal aquifers. Our analyses employ a realistic fluid property (PVT) description of brine-CO2 mixtures for super-critical conditions, which takes into account real gas density and viscosity effects for CO2, and includes pressure, temperature, and salinity dependence of CO2 dissolution into the aqueous phase. The fluid property description has been incorporated into a multi-purpose reservoir simulator, and has been used to evaluate dynamic effects of CO2 injection into aquifers. A survey of minerals commonly encountered in crustal rocks was made to identify possibilities for chemical sequestration of CO2 through the formation of carbonates of low solubility. We also performed batch reaction modeling of the geochemical evolution of representative aquifer mineralogies. Results indicate that under favorable conditions the amount of CO2 that may be sequestered by precipitation of secondary carbonates is comparable to the amount of CO2 dissolved in pore waters. The accumulation of carbonates in the rock matrix and induced rock mineral alteration due to the presence of dissolved CO2 lead to a considerable decrease in porosity.
Downhole Dehydration vs. Reduction of Oil Droplet Break-Up
Authors: van den Broek W. M. G. T. , van der Zande M. J. , Janssen P. H.
Published: December 2007

In downhole dehydration the produced fluids – oil and water, with a low oil/water ratio – are separated at the bottom of the well by means of a hydrocyclone. In many cases this separation can be carried out successfully, because the size of the oil droplets is generally in such a range, that the hydrocyclone can remove the oil from the produced water. Potential problems are connected with the possible occurrence of very small oil droplets, because this may lead to the presence of some oil remaining in the produced water, which is unfavorable from an economical point of view and, moreover, which can lead to difficulties with subsurface injection of this water. Notably production from reservoirs with a relatively low permeability may lead to the presence of small oil droplets.

For conventional high water-cut oil production, the presence of very small oil droplets is predominantly caused by droplet break-up in the choke valve. Further downstream these small droplets determine the complexity of the separation units. It is shown that the geometry of the choke valve influences the break-up process. Consequently, by modification of the geometry of this valve it must be possible to reduce the break-up. It is expected that in this way a substantial droplet size increase can be realized.
Environmental Issues Affecting Deepwater Gulf of Mexico Development
Authors: Clodfelter C. L. , Ratliff M. D.
Published: December 2007

Deepwater exploration and development activities in the Gulf of Mexico have been increasing significantly over the past 5 years and the trend is expected to continue in the future. Early in 2000, the Minerals Management Service released the Gulf of Mexico Deepwater Operations and Activities Environmental Assessment Report (Deepwater EA). The Deepwater EA indentified numerous environmental issues related to deepwater operations. The Deepwater EA discussed the potential environmental concerns related to all aspects of deepwater exploration and production including seismic operations, drilling, production and transportation issues. This paper examines how environmental issues identified in the Deepwater EA will affect operations.
Hygro-Mole: A Logging Tool for Determining Moisture Content in Environmentally Sensitive Subsurface Zones
Authors: Weimer Mindy , Constant W. David
Published: December 2007

The Hygro-Mole's success has been proven both in the laboratory and in the Waste-management Education & Research Consortium (WERC) competition. This logging tool is designed to determine the value of low moisture content present in subsurface regions, at very low cost. The Hygro-Mole yields immediate results, and can be calibrated to specifically monitor multiple types of sub-surface material. This logging tool is a simple, non-invasive technique with virtually no waste stream, and very minimal health and safety hazards.