bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Heat for Recovery of Oil: Field Test Results and Possibility of Profitable Operation
Authors: Walter H.
Published: December 2007

Introduction

Many have studied and experimented with the application of heat to oil sands in an effort to recover oil generally considered to be unrecoverable by conventional means. This interest is understandable because reduction of the viscosity of the oil or, better still, complete evaporation by application of heat seems to be promising and comparatively easy to achieve.

The Worthington Corp., interested chiefly in secondary oil recovery equipment, and the Forest Oil Corp., a pioneer in secondary oil recovery methods, conducted a field test with heat injection and in situ combustion from Sept., 1953, until Aug. 1955. It was established that over 80 per cent of the oil in place could be recovered within that time. The tests were terminated when the oil production rate had fallen off to approximately 40 per cent of its maximum.

In this paper methods and means will be described concerning how this result was achieved and what conclusions may be drawn from the pilot test data with respect to the economy of large scale operations.

History of the Pilot Test, Preliminary Phase

The test site chosen was Parker pool, near Casey, Ill. This reservoir showed poor primary production and a water drive test there covering an area of 17.5 acres was considered unsuccessful. Only 23,000 bbl were recovered in five years from this area. The conditions found in the Pennsylvania sand formation are presented in Table 1.

These conditions are typical of many smaller Mid-western pools, although this oil sand is exceptionally shallow. This shallowness was considered an advantage for a first test of this kind. The pressure to be applied was low and so were the development costs. Also, in case of troubles with the injection and production wells, corrective measures would have been less costly.

A power and heat producing pilot unit suitable for the above listed conditions was built early in 1952 and shipped to the test site, where tests began on Sept. 1, 1953. This equipment has been described previously. It produced a combustion gas-air-steam mixture at maximum pressure of 500 psi, at a maximum temperature of 1,000°F, at a maximum rate of 25 tons per day. Pressure, temperature, and product quantity could be varied in wide range. Also, the composition of the gas-steam mixture could be varied from 100 per cent stir with 23 per cent oxygen by weight to a combustion gets steam mixture containing 53.4 per cent steam, 41.0 per cent nitrogen, 6.6 per cent carbon dioxide, and practically no oxygen.
Review of WAG Field Experience
Authors: Christensen J. R. , Stenby E. H. , Skauge A.
Published: December 2007

In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been reinjected in water-injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG injection has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or the accumulating of water toward the bottom. Because the residual oil after gasflooding is normally lower than the residual oil after waterflooding, and three-phase zones may obtain lower remaining oil saturation, WAG injection has the potential for increased microscopic displacement efficiency. Thus, WAG injection can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and by leading to improved microscopic displacement.

This study is a review of the WAG field experience as it is found in the literature today,1–108 from the first reported WAG injection in 1957 in Canada to the new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG injections with hydrocarbon or nonhydrocarbon gases. Well spacing is very different from onshore projects, where fine patterns often are applied, to offshore projects, where well spacing is in the order of 1000 m.

For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5 to 10% of the oil initially in place (OIIP). Very few field trials have been reported as unsuccessful, but operational problems are often noted. Though the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG injection is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing.
A Review of Bubblepoint Pressure and Oil Formation Volume Factor Correlations
Authors: Al-Shammasi A. A.
Published: December 2007

This paper evaluates published correlations and neural-network models for bubblepoint pressure (pb) and oil formation volume factor (Bo) for their accuracy and flexibility in representing hydrocarbon mixtures from different locations worldwide. The study presents a new, improved correlation for pb based on global data. It also presents new neural-network models and compares their performances to numerical correlations.

The evaluation examines the performance of correlations with their original published coefficients and with new coefficients calculated based on global data, data from specific geographical locations, and data for a limited oil-gravity range. The evaluation of each coefficient class includes geographical and oil-gravity grouping analysis. The results show that the classification of correlation models as most accurate for a specific geographical area is not valid for use with these two fluid properties. Statistical and trend performance analysis shows that some published correlations violate the physical behavior of hydrocarbon fluid properties. Published neural-network models need more details to be reproduced. New developed models perform better but suffer from stability and trend problems.
Implementing Convection in a Reservoir Simulator: A Key Feature in Adequately Modeling the Exploitation of the Cantarell Complex
Authors: Monceau E. , Delamaide E. , Sabathier J. C. , Jullian S. , Kalaydjian F. , DeGuevara J. E. Ladron , Bujanos J. L. Sanchez , Rodriguez F. D.
Published: December 2007

As with some thick and highly fractured Iranian fields, the Cantarell complex located offshore Mexico presents features [decreases in the production gas/oil ratio (GOR) and bubblepoint pressure with time] that reveal the effect of convection.

This effect on the past homogenization of fluid properties is discussed and supported by a thorough characterization of the thermodynamic properties of actual reservoir fluids.

To model convection, the reservoir simulator used for this study was purpose adapted. Sensitivity runs were performed to demonstrate the necessity of accounting for convection when matching the past history of the Akal field, which is part of the Cantarell complex.
Dynamic Simulation and Control-System Design for Gas/Liquid Cylindrical Cyclone Separators
Authors: Wang S. , Mohan R. S. , Shoham O. , Kouba G. E.
Published: December 2007

Gas/Liquid Cylindrical Cyclone (GLCC, copyright, the U. of Tulsa, 1994) separator performance can be improved considerably by adopting a suitable control strategy to reduce liquid carry-over into the gas stream or gas carry-under into the liquid stream. A dynamic model for control of GLCC liquid level and pressure with classical control techniques is developed in this paper for the first time. Detailed analysis of the GLCC control-system stability and transient response indicates that liquid-level control can be achieved effectively by a control valve in the liquid outlet for gas-dominated systems or by a control valve in the gas outlet for liquid-dominated systems. Based on the proposed linear-control system model, the system performance is simulated with a suitable software design tool. Experimental investigations have been conducted to evaluate the liquid-level and pressure-control systems. The novel control-system design approach presented in this paper forms a framework for the GLCC active control-system optimization.
Reservoir Modeling Using Scale-Dependent Data
Authors: Panda M. N. , Mosher C. , Chopra A. K.
Published: December 2007

A reservoir description incorporating the precision and scale of all available data (geological, petrophysical, seismic, tracer, and well-test data) is critical for reservoir modeling. The heterogeneous variables sampled by these data are composed of several superimposed functions, each characterized by a unique spatial and temporal scale or support. For example, core, well-log, well-test, and seismic data have supports ranging from inches to thousands of feet.

Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudopoint properties that assimilate information from all available data are modeled onto model cells using one of several available conditional-simulation techniques. Some methods attempt to combine data with varying support, and data with multiple-scale support, through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case-specific with little generality.

This paper presents a method for identifying the impact of multiscale data (data that measure average property over multiple-flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries, for example, what fraction of core scale variability is captured by well-log data. We also present a consistent method for integrating multiscale data. Through a series of numerical simulations, we show the impact of reservoir-property heterogeneity on the fluid-flow performance.
Behavior of the Bagnore Steam/CO2 Geothermal Reservoir, Italy
Authors: Atkinson P. G. , Celati R. , Corsi R. , Kucuk F.
Published: December 2007

A commonly encountered geothermal steam reservoir consists of a gas cap overlying an aquifer. In addition to steam, the gas cap may contain substantial amounts of carbon dioxide and other noncondensable gases. A mathematical model for describing the pressure and composition histories of such reservoirs is presented. The model evaluates the change in states of a homogeneous vapor/liquid region as a mixture of steam and carbon dioxide is removed from the gas cap and as recharge water enters the liquid region.

The production history of the Bagnore steam field in Italy was evaluated using this model. It is concluded that early reservoir behavior was controlled by a blowdown of carbon dioxide in the gas cap, while long-time behavior is being controlled by water influx.
Control Model of Water Injection Into a Layered Formation
Authors: Silin D. B. , Patzek T. W.
Published: December 2007

Here we develop a new control model of water injection from a growing hydrofracture into a layered soft rock. We demonstrate that in transient flow, the optimal injection pressure depends not only on the instantaneous measurements, but also on the whole history of injection, growth of the hydrofracture, and the rock damage. Based on the new model, we design an optimal injection controller that manages the rate of water injection in accordance with hydrofracture growth and the formation properties. We conclude that maintaining the rate of water injection into a low-permeability rock above a reasonable minimum inevitably leads to hydrofracture growth, to establishment of steady-state flow between injectors and neighboring producers, or to a mixture of both. Analysis of field water injection rates and wellhead pressures leads us to believe that direct links between injectors and producers can be established at early stages of waterflood, especially if the injection policy is aggressive. Such links may develop in thin, highly permeable reservoir layers or may result from failure of the soft rock under stress exerted by injected water. These links may conduct a substantial part of injected water. Based on the field observations, we now consider a vertical hydrofracture in contact with a multilayer reservoir, where some layers have high permeability and quickly establish steady-state flow from an injector to neighboring producers.

The main result of this paper is the development of an optimal injection controller for purely transient flow, and for mixed transient/steady-state flow in a layered formation. The objective of the controller is to maintain the prescribed injection rate in the presence of hydrofracture growth and injector/producer linkage. The history of injection pressure and cumulative injection, along with estimates of the hydrofracture size, are the controller inputs. By analyzing these inputs, the controller outputs an optimal injection pressure for each injector. When designing the controller, we keep in mind that it can be used either offline as a smart adviser, or online in a fully automated regime.

Because our controller is process model-based, the dynamics of actual injection rate and pressure can be used to estimate effective area of the hydrofracture and the extent of the rock damage. The latter can be passed to the controller as one of the inputs. Finally, a comparison of the estimated fracture area with independent measurements leads to an estimate of the fraction of injected water that flows directly to the neighboring producers through links or thief-layers.
Current Steamflood Technology
Authors: Ali S.M. Farouq , Meldau R.F.
Published: December 2007

This paper provides an overview of current steam injection technology. Reservoir data and performance are compiled for 13 selected field projects in the U.S., Canada, and Venezuela. Subjects discussed include oil recovery, well completions, operating practices, and special reservoir conditions. Emphasis is on steamflooding, with some data on cyclic steam stimulation.

Introduction

The purpose of this paper is to help petroleum engineers keep up with emerging steamflood technology, including both reservoir and operating experience. Useful data and references also are provided. provided. Steam injection is the principal enhanced oil-recovery method used today, accounting for 90% of all oil produced by such methods. Prats estimates the total worldwide oil production rate from steam is about 400,000 BOPD (64 000 ml/d oil). The U.S. produces 60% of this total, Venezuela produces produces 60% of this total, Venezuela produces 35%, and Canada produces 3%. Several large projects are in the planning and construction stages projects are in the planning and construction stages for the oil sands of Alberta and the Orinoco oil belt of Venezuela .Steam injection technology has advanced significantly since the status of steam injection was reviewed at a Canadian Inst. of Mining and Metallurgy meeting 6 years ago. The Oil and Gas J.'s annual review for 1978 lists 99 active steam-injection projects for the U.S., 41 for Venezuela, and 14 for Canada . In addition, petroleum engineers have published several technical papers describing field projects and providing greater understanding of how the process can best be applied in the future.The most notable development in steam injection during the past 5 years is the overwhelming shift to steamflooding, with cyclic steam stimulation becoming an important adjunct, rather than a separate oil-recovery process. This is attributed (1) to the relatively low recovery oil recovery attainable by cyclic steam stimulation and (2) to higher oil prices, which have served to make economically attractive the considerably lower oil/steam ratios characteristic of steamfloods.

Field Tests

Table 1 gives formation characteristics and Table 2 lists test results for 13 selected steam-injection field tests. These tests represent most of the major steam-injection projects, except for those reported earlier in Refs. 5 and 6. Unfortunately, a few large projects are not listed in Table 1 because sufficient data were not available. These include Santa Fe Energy Co. Chanslor Div.'s 23,000-BOPD (3700-m3/d oil) Midway-Sunset project, Texaco Inc.'s 35,000-BOPD (5600-m3/d oil) San Ardo project, and several steamfloods in Venezuela. Test 4 (Charco Redondo) is cited in Table 1 primarily because of its unique features. This project was a highly instrumented steam pilot in a thin, waterflooded reservoir. Following the steamflood, the field was flooded successfully by in-situ combustion. Tests 6 and 13 are large, cyclic steam-stimulation projects, and the rest are steamfloods.

JPT

P. 1332
Optimizing Gas-Storage Reservoir Performance
Authors: McVay D. A. , Spivey J. P.
Published: December 2007

As gas storage becomesincreasingly important in managing the nation's gas supplies, there is a need to develop more gas-storage reservoirs and to manage them more efficiently. Using computer reservoir simulation to rigorously predict gas-storage reservoir performance, we present specific procedures for efficient optimization of gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. We present a new, simple procedure to determine the maximum performance with a minimal number of simulation runs. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. We demonstrate a systematic procedure to determine the optimum combination of cushion gas volume, compression horsepower, and number and locations of wells. The use of these procedures is illustrated through application to gas-reservoir data.
Treating Reinjected Oilfield Brine By Microbial Clarification
Authors: Philippovich N. A. , Winter J.
Published: December 2007

Rising water volumes and processing costs in the oil field have spurred OMV to look for alternatives to traditional water processing. Despite an elaborate central multistep water-treating system, increasing injection pressures, water fouling in the pipelines, and reservoir souring were noticed. In a five-year program involving field measurements, laboratory experiments, the construction of a pilot facility, and test injections, a new strategy was adopted. The central water-conditioning plant (WCP) has been revamped. Instead of biocide addition, removal of organic nutrients by a biological clarification step now produces a clear, well injectable, and stable injection water.
Integration of Geology, Geophysics, and Numerical Simulation in the Interpretation of a Well Test in a Fluvial Reservoir
Authors: Raghavan R. , Dixon T. N. , Phan V. Q. , Robinson S. W.
Published: December 2007

The focus of this paper is the incorporation of geologic and geophysical data in the analysis of pressure tests in a fluvial reservoir. Using a 3,105,851-cell "porosity cube" derived by seismic and well-log data, this work outlines the steps involved in developing a 3D model with 7,128 cells that was used to estimate reservoir properties (such as permeability, skin, permeability/porosity relationship, reservoir connectivity, and fault factor). The principal steps involved in developing the reservoir model include:

identifying all points in the porosity cube that were connected to the wellbore, with porosities above a specified cutoff to identify high-porosity channels and low-porosity overbanks, upscaling the porosity cube to a reasonable size for well-test simulation while preserving pay thickness, pore volume, and connectivity between high- and low-porosity materials; and matching the observed pressure and pressure-derivative responses with a numerical simulator and a regression program to automatically adjust the reservoir permeability description.

A well test in a gas-condensate reservoir is used to demonstrate the ideas outlined in this work. This approach allowed us to identify not only horizontal permeability but also vertical permeability. The issues that need to be considered and the conclusions that are derived on the basis of this work differ significantly from conventional interpretations.
Effect of Pore-Lining Chlorite on Petrophysical Properties of Low-Resistivity Sandstone Reservoirs
Authors: Durand Claudine , Brosse Etienne , Cerepi Adrian
Published: December 2007

Chlorite-bearing sandstones usually give low resistivity signals and are thus erroneously identified as nonpay zones, even if they exhibit good preserved porosities at depth. The purpose of this paper is to provide petrophysical and mineralogical laboratory measurements that help improve the log interpretation of these sandstones.

The main results were obtained from a selection of reservoir cores. For sandstones having an amount of chlorite between 3 and 11 wt%, they show that the cementation index and saturation exponents (m and n) have values lower than 2, with n frequently around 1.5. These low values have been checked carefully to avoid experimental artifacts. Cationic Exchange Capacities (CEC) and Specific Surface Areas (SSA) both have low values, as expected from the clay structure. The distribution of pore throats is bi- or tri-modal, with a large contribution of microporosity.

The interpretation suggested by these results is that the amount and distribution of microporosity associated with pore-lining clay is the key to the chlorite sandstone electrical behavior. The values of CEC or SSA are too low to fully explain the low values of the saturation index n.

Use of these low values in log interpretation has the effect of increasing the interpreted oil in place. Advantages of a multidisci-plinary approach for better evaluation of such complex argillaceous sandstone reservoirs is highlighted.
Delineating the Pour Point and Gelation Temperature of Waxy Crude Oils
Authors: Venkatesan Ramachandran , Singh Probjot , Fogler H. Scott
Published: December 2007

Paraffin deposition in subsea pipelines is a multimillion-dollar problem in the oil industry. The temperature at which a waxy crude oil gels is an important property that determines the initiation of the deposition process. The "pour point," as defined by the standard ASTM test method, is not sufficient to describe the deposition of waxy crudes under flow conditions. The "gelation temperature," explained in this article, is found to be an appropriate measure of the onset of gelation under static as well as flow conditions. Rheological experiments show that the gelation temperature of a wax-oil system is depressed by the shear stress acting on the system during cooling.
Design, Fabrication, and Installation of the Ninian Field Southern Platform
Authors: Hancock M.V. , Nay M.C. , White E.I.
Published: December 2007

In an effort to eliminate problems previously experienced in fabrication and installation of large steel structures, emphasis for the Ninian field southern platform was placed on designing for those factors as well as for functional and long-term loadings. This paper describes design and innovative features of the structure.

Introduction

Chevron's Ninian field southern platform is noteworthy for its rapid planning, design, fabrication, and extremely successful installation, all of which justified the conceptual philosophy adopted early in the design stage. The aim was to build on past experience and to provide simplicity and refinement within the limits of available technology, consistent with a summer 1977 installation of a platform capable of supporting the heaviest deck load yet proposed for a piled steel structure. These goals, together with severe functional and environmental criteria, resulted in a number of interesting features.This paper describes the process leading to the selection of a self-floating steel tower and outlines the manner in which considerations of fabrication, transportation, and installation influenced the configuration of structure and piles.

Selection of Platform Type, Factors Influencing Configuration

It was believed that the success of the proposed program would rely as much on designing for fabrication and installation requirements as on structural analysis and design. In the overall development cost, the effect of saving structural steel weight by virtue of exhaustive analytical work is insignificant; on the other hand, time spent on designing for fabrication and installation can result in significant cost savings.

Description of Tower

The Ninian field southern platform is a four-leg, piled, steel-tower structure supporting modular production and drilling facilities (Fig. 1). It is a self-floating unit with an integral ballasting system designed for remote-controlled operation.The deck comprises two levels of modules, 65 × 68 m in plan, providing three main levels, with a nominal production capacity of providing three main levels, with a nominal production capacity of 150,000 BOPD. Maximum anticipated deck load is 26 000 t, including two drill rigs. Slots are provided for 42 conductors.Typical dimensions are 75 × 75 m center to center of the legs at the mudline, tapering to 55 × 55 m at the top of the module support skid beams. Overall height from mudline to skid beams is 168.5 m.The tower is supported by 32 skirt piles, 1825 mm OD with walls 63 mm thick, arranged in clusters of eight at each leg in a 12.2-m diameter circular pattern.Storage is provided in the upper parts of the 9.2-m diameter flotation legs for 20,000 bbl of diesel fuel and 10,000 bbl of drilling water.

JPT

P. 1366
High-Density Monomer System for Formation Consolidation/Water-Shutoff Applications
Authors: Eoff Larry , Funkhouser Gary P. , Cowan Mike
Published: December 2007

This paper describes an in-situ polymerizable organic monomer hydrogel system for formation consolidation during deepwater drilling applications in which a water-soluble vinyl monomer solution is polymerized in-situ to seal and consolidate unstable geological zones. In deepwater wells, shallow zones may have pore pressures close to parting pressures. In these situations, lost circulation or flowing zones can be difficult to control and can lead to a complete loss of the well.

Hydroperoxide and azo initiators are used for polymerizing solutions of 2-hydroxyethyl acrylate monomer in aqueous solutions of synthetic seawater, sodium chloride (NaCl), calcium chloride (CaCl2), calcium bromide (CaBr2), and zinc bromide (ZnBr2), with densities from 8.6 to 17.5 lbm/gal. These monomer solutions undergo controlled polymerizations in the formation to yield a crosslinked hydrogel matrix that can withstand high differential pressures. A similar monomer system has been used for water-shutoff applications but had never been formulated in heavy brines or used in the cool temperatures (50 to 60°F) typical of the shallow water-flow zones. The use of a high-density hydrogel for consolidation purposes would be an advantage in shallow water-flow zones because the gelant solution of the hydrogel could be spotted over, and allowed to flow into, the problem zone where the gelant flow is driven by the hydrostatic pressure of the treatment fluid. This process enables the use of the monomer system in wells where high-pressure injection of the treatment fluid into the formation is not an option.

This article describes the hydrogel system's development, including gel-time curves and compressive strengths of consolidated sandpacks, and discusses factors affecting the performance and application of the system.
Deepwater Tie-Ins of Rigid Lines: Horizontal Spools or Vertical Jumpers?
Authors: Corbetta Giovanni , Cox David S.
Published: December 2007

Movement toward deeper waters and harsher environmental conditions has required the continuous development of new technologies, and will continue to do so. In particular, this need has manifested itself in the design and operation of remote tooling to complete subsea field developments.

One of the principal problems faced during both the design and operational phases of a project is the definition of methods and systems to perform the tie-in of production lines to subsea facilities. This problem, in fact, influences some critical decisions such as the type of lines used (rigid/flexible), the structure layout (tie-in porches and interfaces), and the method of installation (first- or second-end connections).

Different systems to perform remote connections of either flexible or rigid lines have been developed. Among these, special attention was paid to rigid line connections, which are the preferred option of the industry for both technical and economic reasons. This new focus has, in turn, led to the development of systems able to perform tie-ins of rigid lines using either horizontal spools or vertical jumpers. This paper presents a comprehensive comparison between these two methods, including an overview of the systems considered and an outline of advantages and drawbacks, both technical and financial, of the two solutions.
A Geostatistical Approach to Streamline-Based History Matching
Authors: Caers Jef , Krishnan Sunderrajan , Wang Yuandong , Kovscek Anthony R.
Published: December 2007

History matching large reservoir models under a realistic geological continuity constraint remains an outstanding problem. We propose a new combined geostatistical and streamline-based method potentially capable of history matching large reservoir models, while accounting consistently for geological continuity as provided by a permeability histogram and variogram and by production data. While most existing history-matching techniques somehow rely on the calculation of single-gridblock sensitivity coefficients, the proposed method avoids such calculation entirely by perturbing jointly effective permeabilities along a set of streamlines. Such perturbation results in large changes of the permeability field that reduce significantly error in each iteration of the history-matching procedure. The problem of mapping streamline effective permeability perturbations to single gridblocks is performed under a Gauss-Markov random function constraint. This novel stochastic mapping procedure accounts for the target histogram and variogram while honoring the streamline effective permeability perturbations. Forward flow simulation is achieved by a streamline simulator. The methodology is presented on synthetic cases; it appears to be computationally efficient and robust.
Feasibility Study of the Stability of Openhole Multilaterals, Cook Inlet, Alaska
Authors: Moos D. , Zoback M. D. , Bailey L.
Published: December 2007

A study of in-situ stress, rock strength, and wellbore stability was initiated in the Hemlock sands of the McArthur River field, Cook Inlet, Alaska, to evaluate the potential of leaving the near-wellbore portions of multilaterals uncased. A northwest/southeast direction of maximum compression and a strike-slip faulting regime were predicted from analyses of leakoff test data and observations of failure (breakouts) in adjacent wells. Caliper, well-log, and core data indicated that cementation, and hence rock strength, is highly variable within the reservoir. Thus, it was decided to evaluate the stability of the lateral sections (i.e., the likelihood of wellbore failure during production) as a function of both stratigraphic position and well orientation. Laboratory rock-strength measurements were carried out on cores selected from target intervals in adjacent wells to provide sufficient precision to quantify the results. The results indicated that, while some reservoir intervals have high enough strengths to be left uncased when drilled in the most stable direction, these intervals are too thin to provide sufficient support at the point where the laterals leave the parent well. This justified the decision to case back the laterals to the parent well despite the cost.
Orienting Live Well Perforating Technique Provides Innovative Sand-Control Method in the North Sea
Authors: Eriksen Jan Hilding , Sanfilippo Francesco , Kvamsdal Arne L. , Flint George , Kleppa Erling
Published: December 2007

The Varg field is a development in the North Sea operated first by Saga Petroleum and currently by Norsk Hydro. It consists of a not-normally-manned wellhead platform (WHP) with dry wellheads and a floating production storage offloading (FPSO) vessel for processing the crude. The reservoir is heterogeneous sandstone of Upper Jurassic age, with estimated reserves of approximately 35 million STB.

During development planning of the field, it was felt that sand production was likely to occur, and this phenomenon was actually experienced during well testing. Because this development was considered to be a marginal field, an extensive program was initiated to review and select a technical completion solution that would minimize the risk of sand production so that production potentials could be maximized. This paper discusses how a unique perforating solution was developed to provide the controls needed to manage the potential for sand production.

The first part of this paper summarizes (1) the drainage strategy, and the implications of that strategy on selecting the perforation intervals, and (2) the results of a rock mechanics study that focused on the conditions critical for the onset of sand production, as well as recommendations for minimizing the risk. The primary recommendations were to avoid perforation of the weakest intervals and to shoot perforations that would be oriented parallel to the maximum horizontal stress.

The second part of the paper describes how successful oriented perforating was achieved in these wells. The primary completion challenges included the following:

Development of a slickline system that could perforate the entire zone simultaneously in a given direction in a vertical well. A means to remove the perforating guns from the well without having to kill it after completion of the perforation, as there was insufficient rathole to leave the guns in the hole.

An oriented modular perforating system was developed so that these conditions could be achieved. The requirements were met by installing a gun anchor in the well before the completion was installed. Then, the orientation of an orienting lug was measured with a gyro, and, based on the data from the survey, the guns were aligned in the correct orientation. Subsequently, gun sections of length maximized to available lubricator length were run on slickline. The gun section aligned itself automatically to the measured orientation of the orienting lug because of the equipment design. Currently, three wells have been perforated using this system. All of them are sand-free since startup 1½ years ago.
Evaluation of the Steam-Injection Process in Light-Oil Reservoirs
Authors: Dehghani Kaveh , Ehrlich Robert
Published: December 2007

Feasibility of steam injection for three light-oil reservoirs in different geologic settings has been evaluated. The settings studied were a waterflooded deltaic sandstone, a waterflooded vuggy dolomite, and a deltaic sandstone structural trap with a gas cap. Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.

Results show that light-oil steamfloods can be designed to take advantage of post-secondary oil-saturation distribution. The resulting project may be carried out in a considerably different fashion from that of conventional heavy-oil steamfloods.

We also re-evaluated an unsuccessful light-oil steamflood (LOSF) project carried out in the past. The re-evaluation correctly predicted failure because of early steam breakthrough. The results show that by considering details of geology and displacement process physics, the recent advances in reservoir characterization and modeling tools enable us to predict the performance of these projects more accurately.
How To Manage Drill-In Fluid Composition To Minimize Fluid Losses During Drilling Operations
Authors: Cobianco S. , Bartosek M. , Lezzi A. , Guameri A.
Published: December 2007

Selection of the best drill-in fluid for drilling horizontal wells is essentially based on the characteristics of the filter cake formed in the near-wellbore region. Minimizing filtrate loss into the formation by forming a thin filter cake with low porosity and permeability is the key to managing formation damage problems.

In this paper, the effects of drill-in fluid components and their interactions in the formation of a filter cake, which provides an effective caking process with reduced filtrate loss, have been evaluated. Statistically designed experiments carried out with a dynamic filter press apparatus were used to identify which variables had the most significant effect on filtrate loss and cake permeability so that the optimum fluid composition could be determined. These variables include the formation characteristics (permeability and pressure values) as well as the type and amount of the fluid components.

Data obtained in this experimental design study were analyzed with the multiple-linear-regression method, which allowed us to model the filtrate loss and cake permeability. The analysis showed that the most important factors are the type and the concentration of the polymer. In particular, when the formation temperature is as high as 90°C, we can reduce the cake permeability and the filtrate loss by increasing the concentration of scleroglucan. An interaction effect between the concentration of scleroglucan and the more highly crosslinked starch was also identified, and none of the other variables showed any significant effects within the range of experimentation. This fact can be considered as an advantage because it allows flexibility in the choice of other factors when appropriate for the cost reduction.
Impact of Reservoir Mixing on Recovery in Enriched-Gas Drives Above the Minimum Miscibility Enrichment
Authors: Solano R. , Johns R. T. , Lake L. W.
Published: December 2007

Gas enrichment is an important variable used to optimize oil recovery in enriched-gas drives. For slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the minimum miscibility enrichment (MME). For field projects, however, the optimum enrichment required to maximize recovery on a pattern scale may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2D effects, such as channeling, gravity tonguing, and crossflow, can impact the enrichment selected.

Numerical simulation is often used to model the effect of physical mixing on oil recovery in miscible gasfloods. Unfortunately, numerical dispersion can cloud the interpretation of the results by artificially increasing the level of mixing in the reservoir.

This paper investigates the interplay among various mixing mechanisms, enrichment levels, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. The U. of Texas Compositional Simulator (UTCOMP) is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods, including higher-order methods. The reservoir fluid used for all simulations is a 12-component oil displaced by gases enriched above the MME.

The results show that for 1D enriched gasfloods, the recovery difference between displacements above the MME and those at or near the MME increases significantly with dispersion. The trend, however, is not monotonic and shows a maximum at a dispersivity of approximately 4 ft. The trend is independent of relative permeabilities and gas trapping for dispersivities of less than approximately 4 ft. For 2D enriched gasfloods with slug injection, the difference in recovery generally increases as dispersion and crossflow increase. The magnitude of the recovery differences is less than that observed for the 1D displacements. Recovery differences for 2D models are highly dependent on relative permeabilities and gas trapping. For water alternating gas (WAG) injection, the differences in recovery increase slightly as dispersion decreases. That is, the recovery difference is significantly greater with WAG at low levels of dispersion than with slug injection. For the cases examined, the magnitude of recovery difference varies from approximately 1 to 8% of the original oil in place (OOIP).
Use of Color Movies for Interpretation and Presentation of Reservoir Simulation Results
Authors: Good P.A. , Rogers W.L. , Rester S. , Smith R.A. , Dodge L.P.
Published: December 2007

Motion pictures made from color-coded spatial distributions for fluid saturations, phase compositions, pressure, and temperature are applied to the interpretation of reservoir simulations. The use of computer animation is described as applied to several enhanced oil-recovery processes. Additional insight into simulation results can increase markedly the potential value of numerical simulation.

Introduction

Use of mathematical reservoir simulators to correlate reservoir data and to predict the behavior of petroleum reservoir recovery processes has become an important part of modern reservoir engineering. In addition to the major technical difficulties inherent in developing and running these simulators, it has been found that it is frequently difficult and time consuming to interpret and present the results from simulators. One underlying cause of this difficulty of interpretation and presentation of simulator results is the quantity of information provided by simulators. For example, a typical compositional thermal simulation (three components) might employ five wells and 300 grid blocks. At each grid block, temperature, pressure, three saturations, and an additional composition are available at each time step. Well rates and pressures, perhaps at several different completion intervals, also are calculated. If the simulation takes 300 time steps to run to completion, more than 450,000 numbers will represent the "solution" to the particular reservoir engineering problem (approximately 1,350,000 intergrid block fluxes also would have been computed and used by the simulator during the simulation). As several dozen of these simulations might be made during a field study, it is clear that the simulator user can be faced with more information from the computer than can be assimilated or interpreted conveniently.A second source of difficulty is the inherent two- and three-dimensional aspects of many simulations. It is straightforward to represent graphically the dynamic history of one-dimensional quantities such as well rates as a function of time. Two-dimensional quantities, such as water saturation as a function of position in a vertical cross section, are more difficult to display on a graph. One commonly used display method for two-dimensional cross sections is line-printer contour plots (Fig. 1). While contour plots provide for a rapid visual evaluation of spatially distributed quantities, a distinct advantage over tables of numbers, these plots have several disadvantages.1. They have a low information content - i.e., a number of such plots would have to be viewed simultaneously to provide a picture of all the reservoir variables in a given cross section at one point in time.2. The spatial resolution and the contour resolution of the plots are low.3. It is generally difficult to gain an appreciation of reservoir dynamics from these static "snapshot-in-time" representations of reservoir conditions.

JPT

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Selectively Placing Many Fractures in Openhole Horizontal Wells Improves Production
Authors: Love T. G. , McCarty R. A. , Surjaatmadja J. B. , Chambers R. W. , Grundmann S. R.
Published: December 2007

This paper presents the results of a study on an openhole well that was treated with a new fracturing process—hydrajet fracturing. In only a single pass, hydrajet fracturing allows operators to use high-pressure jets to place multiple fractures accurately in several locations in a well. To fracture the well most effectively, the process uses surface and downhole data recorders to monitor well conditions. Study results show that the hydrajet fracturing process is an effective, economical method for fracture-treating openhole horizontal wells.
Wellbore Storage and Skin Effects During the Transient Flow of Non-Newtonian Power-Law Fluids in Porous Media
Authors: Ikoku Chi U. , Ramey Henry J.
Published: December 2007

A model recently presented by Ikoku and Ramey for non-Newtonian power-law flow in porous media was extended to flow in finite circular reservoirs. A constant flow rate was stipulated at the wellbore, and two boundary conditions were considered: no-flow outer boundary and constant-pressure outer boundary. The results were used to derive a new expression for the stabilization time for power-law flow in porous media.

Wellbore storage and skin effects always distort the transient pressure behavior of wells in petroleum reservoirs. It is important to investigate the consequences of these phenomena and be able to interpret real well test information. This paper considers the effects of skin and wellbore storage on the transient flow of non-Newtonian power-law fluids in petroleum reservoirs.

A new numerical wellbore storage simulator was used to study the effects of skin and wellbore storage during the transient flow of power-law fluids in infinitely large and finite circular reservoirs. Results are presented both in tabular form and as log-log graphs of dimensionless pressures vs dimensionless times. The log-log graphs may be used in a type-curve matching procedure to analyze short-time well test data.

The early period is dominated by wellbore storage effect. A new expression was obtained for the duration of wellbore storage effect when skin exists for infinitely large reservoirs. This criterion is not valid for finite circular reservoirs with no-flow outer boundary or constant-pressure outer boundary. Results indicate that there is no apparent end of wellbore storage effect for the no-flow outer boundary condition for the values of external radius presented. New relationships were derived for skin presented. New relationships were derived for skin factor and "effective well radius" for power-law flow.
Gel Propagation Through Fractures
Authors: Seright R. S.
Published: December 2007

Based on experimental results, a model was developed to quantify gel propagation and dehydration during extrusion through fractures. To maximize gel penetration along fractures, the greatest practical injection rate should be used. On the other hand, in wide fractures or near the end of gel injection, gel dehydration may be desirable to form rigid gels that are less likely to wash out after placement. In these applications, reduced injection rates may be appropriate. Significant advantages could be realized for gels made with a polymer that has the largest available molecular weight.