bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Fireflood - Carlyle Field, Kansas
Authors: Elkins L.F. , Skov A.M. , Martin P.J. , Lutton D.R.
Published: December 2007

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

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Pilot tests of forward combustion were conducted in 35 to 45 ft oil-saturated sand overlying 100 to 125 ft water-saturated sand in the Bartlesville sand at a depth of 860 ft. Ignition and maintenance of combustion were achieved easily. Cold wells typically produced 0.5 to 2 B/D of 700 cp 19 degrees API oil. After heat breakthrough, and in some cases after various stimulation treatments, some individual wells had peak production rates of 40 to 60 BOPD. However, peak production rates of 40 to 60 BOPD. However, typical average production rates of wells were 3 to 10 BOPD. Post combustion coring in the initial 2.5 acre 5-spot pilot indicated much of the burning occurred in the water sand which contained 5 to 15 percent residual oil saturation - enough oil to support combustion.

Many different attempts were made to increase productivity of cold wells. These stimulations included injection of various solvents, de-emulsifiers, acids, etc. into the sand, and steam soak, burn treatment, and fracture treatment. Although some of these efforts resulted in significant increases in oil production rate, generally, the effects were short lived. We were unsuccessful in achieving sustained oil production rates by forward combustion which production rates by forward combustion which would indicate profitable operation on an expanded multiple pattern basis.

With lack of success in forward combustion, as a last resort, we converted two ignited air injection wells to production and two cold producing wells to air injection for a test of producing wells to air injection for a test of reverse combustion. The better of the two hot producing wells achieved a sustained rate of producing wells achieved a sustained rate of 25 BOPD with an instantaneous combustion GOR of about 40,000 cu ft/bbl. The cumulative average GOR of this well was 68,000 cu ft/bbl. Tests of an observation well 100 ft from this producing well indicated much of the combustion producing well indicated much of the combustion occurred in the water zone. Later, tests of the observation well, backflow tests of the two cold air injection wells, and tests of other wells indicated that spontaneous ignition had occurred within 8 to 10 months in the vicinity of the injection wells. This precludes reverse combustion operation in this reservoir at any economically attractive well spacing.

Introduction

Starting in February 1963 and continuing into 1966, Layton Oil Company operated an underground combustion test in the Bartlesville sand, Carlyle Field, Allen County, Kansas. Results of this test which included 4 air-water injection wells and 12 producing wells in an 11-acre area were reported by M. W. Smith in 1966.
Heavy Oil Recovery by Steam-Driven Hydrocarbon Slugs from Linear Porous Media
Authors: Alikhan Abbas A. , Ali S.M. Farouq
Published: December 2007

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

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This work was principally concerned with an experimental study of oil recovery from a porous medium by the injection of a light hydrocarbon slug, followed by a steam slug, which is in turn driven by a conventional waterflood. An attempt was made to simulate the experiments by use of a cell model. The experiments involved fluid displacements in two glass bead packs having a rectangular internal cross-section of 1.75 × 3.75 in and 48 in length, overlain and underlain by 1.5 ft thick sand packs to simulate the adjacent formations.

The core initially contained a residual oil saturation or a high initial oil saturation, corresponding to the irreducible water saturation. Drakeol 33 and Drakeol 35 (viscosities of 152 and 209 cp, respectively) were employed as the inplace oils, while isooctane, Soltrol C, Kendex 0837, Drakeol 9, Drakeol 15, and three mixtures of Soltrol C and Drakeol 33, Kendex 0837 and Drakeol 9, and Drakeol 9 and Drakeol 35 (viscosities of 0.5, 1.3, 11.3, 23.4, 49.4, 6.4, 17.4, 73.3 cp, respectively) were used as the light hydrocarbon slug materials. Light hydrocarbon slug sizes of 5, 10, and 25% PV were employed, while the steam slug size ranged from 19 to 66% PV, with an average of 35.7% PV. The steam injection rate ranged from 11 to 150 ft/day.

It was found that the light hydrocarbon slug injected prior to the steam slug in a core initially containing a residual oil saturation improved the oil recovery as compared to a straight steam slug run. The light hydrocarbon, in view of the prevailing adverse mobility ratio, mixes with the original inplace oil, and helps to lower its viscosity. This viscosity is further reduced by the heat from the injected steam slug, leading to an improvement in the mobility ratio, and hence an improvement in the displacement efficiency. A large proportion of the light hydrocarbon slug is recovered by the steam distillation effects. It is concluded that from the recovery ratio (volume of oil recovered divided by hydrocarbon slug volume) point of view, it is advantageous to use a low viscosity light hydrocarbon slug, and a small slug size. The optimum slug size depends on the in-place oil, as well as the steam slug size, for a given steam temperature.

The temperature profiles and the heat loss rate measurement indicated that the combination, light hydrocarbon slug-steam slug, process utilizes the maximum amount of heat injected, hence increasing the thermal efficiency of the process. process.
Principal Permeability Determination from Multiple Horizontal Well Tests
Authors: Muñoz Alberto , Ehlig-Economides Christine , Economides Michael J.
Published: December 2007

Horizontal wells have forced a reconciliation with the concept of permeability anisotropy: vertical-to-horizontal and horizontal-to-horizontal. The former, if favorable, may indicate whether a horizontal well is attractive compared to a vertical well; the latter is important in well orientation. While other authors and we have postulated at least a qualitative relationship between stress and permeability orientation and we have suggested that wells should be oriented normal to the maximum stress/permeability orientation, it is often neither easy nor possible to measure stresses. In fact substantial permeability anisotropy has been found even in formations where stresses approach isotropy. In unconsolidated or loosely consolidated formations stress measurements may not even be plausible. Productivities deviate substantially among wells in the same reservoir and the well orientation has been considered as a major reason.

There is, therefore, a compelling rationale to detect and measure permeability anisotropy. Ideally this should be done before a horizontal well program is initiated in a reservoir, but if this is not possible, shortly thereafter. Both vertical and horizontal pressure interference testing have been used for permeability determinations. Under the assumption that the geometrical mean permeability, k¯, is available from a vertical well test, other authors have suggested that tests in two horizontal wells, forming an angle between them, can provide the values of the two principal horizontal permeabilities. We are suggesting a further development requiring only the linear flow regime in three arbitrarily-oriented horizontal wells. A field case study illustrates the approach. Using the analysis results, the optimal well trajectory is determined, and economics of the misorientation are computed.
Improved Waterflooding Efficiency by Horizontal Wells
Authors: Popa C. G. , Clipea M.
Published: December 2007

Due to the improvements in the technology of horizontal well construction, there is a tendency to extend the use of horizontal wells for improving the overall efficiency of different recovery processes, including waterflooding. Using horizontal wells in a waterflooding process, a higher sweep efficiency for less cost is expected as opposed to the use of classical patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate such a process.

The paper presents an analysis of how the overall efficiency of a waterflooding process is influenced by the well pattern using horizontal wells. Three cases were taken into consideration: first for a pattern using two parallel horizontal wells, one for injection and the other for production, second for a pattern using one horizontal well for water injection and few vertical wells for production, and the third for a pattern using vertical wells for injection and one horizontal well for production.

A two phase two dimensional numerical model was used to make the simulation of the waterflooding process for each case. The results showed that the pressure loss along the horizontal section has a large influence on the sweep efficiency both for using an injection and/or a production horizontal well. Also, the results showed that it is preferable the use of vertical wells for injection and horizontal wells for production rather then the use of horizontal wells for injection and vertical wells for production.
SAGD Operating Strategies
Authors: Nasr T. N. , Golbeck H. , Korpany G. , Pierce G.
Published: December 2007

The steam assisted gravity drainage (SAGD) process has emerged as an effective technology for the recovery of oil from oil sands deposits that are deeply buried for surface mining. In general, the process involves drilling paired horizontal wells, one well above the other and separated by a distance, near the bottom of the oil-bearing formation. The top well is used to inject steam into the oil sands, heating up the oil and allowing it to drain, under the action of gravity, into the bottom well.

The paper first provides a review of the technological advances made in SAGD operating strategies. In addition to the successful field testing at the Underground Test Facility (UTF), the SAGD process has been recently extended to other types of reservoirs. These include reservoirs with lower permeability as compared to that at the UTF site and reservoirs with bottom water transition zones. Challenges facing application of the process in such types of reservoirs will be discussed. Concepts to overcome the challenges will be presented in terms of laboratory studies that have been carried out. The concepts tested include: the use of mechanical means such as drilling vertical drainage channels between paired horizontal wells; combining a vertical well with paired horizontal wells and potential for solvent and gaseous additives in steam (to improve SOR and reduce water requirements). Results provide valuable observations for field scale development of a more robust and economically viable process.
Numerical Investigation of SAGD Process Using a Single Horizontal Well
Authors: Shen C.
Published: December 2007

Recently several articles have been published regarding the innovation and field applications of the Steam-Assisted-Gravity-Drainage (SAGD) process using a single horizontal well for the recovery of heavy oil. In the process, an insulated concentric coiled tubing, inserted into the horizontal wellbore, injects high quality steam to the toe of the well. The steam condensate and reservoir fluids enter the wellbore and flow back along the annulus to the heel to be produced.

There remain some arguments on whether the SAGD mechanism is working in field operations, and on what oil rates can be achieved in the long run. In an attempt to answer these questions, numerical simulation studies were pursued in the present work. The studies focused on three major aspects: (1) the possible counter-current fluid exchange pattern between the reservoir and the well; (2) the means that could be exploited to promote the initiation of a steam chamber; and (3) the potential oil rates that could be expected under possible field operating conditions. The results showed that the presence of small capillary pressure near a horizontal wellbore is a physical constraint preventing counter-current exchange of steam and oil. It was also demonstrated that vertical undulation in well-profile or a certain level of formation dilation around the wellbore could potentially overcome the capillary pressure constraint and promote the initiation of a steam chamber under field operating conditions.
Application of a Non-Equilibrium Reaction Model for Describing Horizontal Well Performance in Foamy Oils
Authors: Saputelli B. Luigi A. , Canache P. Carlas M. , López Elías
Published: December 2007

Improving the hydrocarbon recoveries for reserves is actually regarding new technologies and better porous media understanding. Approximately 300,000 millions barrels of additional extra heavy oil were exploitable from Orinoco Belt in Venezuela if suitable explotation strategies were oriented to profit natural mechanisms from existing oil reserves.

The purpose of this paper is to study the sensibility of the activation energy and frequency factor of chemical reaction in heavy oils of the Orinoco Belt in Venezuela. This model accounts for the kinetics of physical changes that occur in the morphology of the gas-oil dispersion. Non-equilibrium reaction model was used in order to model foamy oil behavior observed at SDZ-182 horizontal well in Zuata field. Foamy oil modelling requires the investigation of the activation energy and frequency factor ranges that describes the non-equilibrium reaction model. These ranges were used to obtain a reasonable 3-years history match of SDZ-182 well. Activation energy ranged from 0 to 0.01 BTU/lb-mol and frequency factor ranged from 0.001–1000 1/day for first reaction. For second reaction, activation energy was 50×103 BTU/lb-mol and frequency factor 2,75×1012 1/day. Parameters of the second reaction are more sensitive to any variation than first reaction parameters. This paper describe suitable methodology to match foamy oil behaviour in horizontal wells under cold production and steam stimulation processes.
Opukushi Horizontal Well Campaign: Completion Design and Wellbore Clean-Up
Authors: Osode P. I. , Dijkema R. W.
Published: December 2007

As part of on-going initiatives to improve the Opukushi field ultimate recovery and production potential, horizontal well technology was introduced during the second phase of the field development, which started in 1995. Following the review of three previous wells, including the first Shell-Nigeria horizontal well, which was completed in 1992, some modifications of the completion design were recommended. While still on the learning curve of drilling horizontal wells, another 3-well horizontal drilling campaign was successfully executed in the Opukushi field in 1996.

Openhole liner completion design was selected because of the unconsolidated sandstone formation which characterizes the shallow horizons of the field, with the wells targeting undeveloped reserves located at a depth of ~7500 ft tv-ss. All the wells were completed in thin oil rim sands of ca. 70 ft, with 5-1/2" × 4-1/2" tapered slotted liner (SL) assemblies installed across 2300–3300 ft of 8-1/2" drainhole sections. The horizontal sections were drilled with a low-solids drill-in fluid while wellbore clean-up was effected with a coil-tubing unit utilizing a nitrified acid at underbalance condition.

This paper presents a review of the 3-well completion design and installation technique, as well as the horizontal wellbore clean-up procedure adopted. The wells’ performance evaluation, based on test data and Production Logging Tool (PLT) results, has also been presented to show a comparison with the conventional well performance. The recorded high productivity improvement factor (PIF) of above 10 has demonstrated the superiority of horizontal well applications.
Optimizing Fracture and Completion Designs in the Westerose Field
Authors: Aunger D. , Dunn-Norman S. , Kenny J. , Halvaci M. , Griffiths E. , Barnhart W.
Published: December 2007

The Westerose Gas Field produces gas from the Glauconitic Formation. This formation can be subdivided into an upper permeable sand (1–10 mD) and a lower sand (normally less than 0.5 mD). The reservoir quality of the lower sand is fairly uniform throughout the area, but the upper section can contain either permeable "bar" sands or low permeability "interbar" sands. "Bar" type sands have greater thickness than the "interbar" sands and, in general, contain greater gas reserves. Nevertheless, inter-bar sands are estimated to contain up to 225.4 MMm3 (8 Bcf) original gas in place per section, which is a significant gas target. These reserves have not been extensively developed since vertical wells that penetrate the interbar sand are usually very poor producers.

An experimental pilot project was conducted to determine the feasibility of developing additional gas reserves in the tight sands located between the main bar trends. As part of this work, a study was conducted to analyze and compare fracturing and completion alternatives in the Glauconitic "bar" and "interbar" sands. For each type of sand, optimal fracture designs for vertical wells were determined and vertical fractured well performance was compared to stimulated and unstimulated horizontal wells drilled either parallel or perpendicular to the minimum in-situ stress. This paper reports the findings of the Westerose fracturing and completions study, and field results from wells drilled and completed in 1997 in accordance with the study recommendations.
Gulf Of Alaska Wave Climate Program
Authors: McLeod Wilfred R.
Published: December 2007

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

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper deals with a new deep water wave data acquisition program. The author believes that program. The author believes that the uniqueness of design, as well as planning, that went into this program will be invaluable to others program will be invaluable to others contemplating wave climate studies in other coastal locations. Detailed information on equipment selection and method of data analysis is provided. The potentially strong provided. The potentially strong currents, up to 5 knots, that will be encountered in the study area, and the limited buoyancy of the standard (0.7-M) Waverider, pose a difficult mooring problem. The use of Waveriders of larger diameter (0.9-M) along with the mooring system to be used in this study are discussed.

Wave spectra measurements made during severe and normal conditions will help to compensate existing severe and normal hindcasts. The data will also be especially useful for testing new operational forecasting schemes, in an analytic sense, as the complete records become available.

Introduction

The wind and resulting wave climate is a principal concern to those responsible for offshore operations of the petroleum industry. This is particularly true for heavy weather areas such as the Gulf of Alaska, where the design of safe and yet economical offshore structures depends on accurate design wave criteria. A data base which includes actual wave measurements is important to the development of reliable statistics. Thus, knowledge of both normal and storm wave conditions is essential to the formulation of logistic, operating, and construction plans.
Interpretation of Horizontal Well Performance in Complicated Systems by the Boundary Element Method
Authors: Jongkittinarukorn Kittiphong , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

This paper presents the solutions obtained by using the boundary element method to simulate pressure behavior of horizontal wells in complicated reservoir-wellbore configurations. Three different types of wellbore and reservoir models studied by Jongkittinarukorn (1998) are reported in this study. They consist of a snake-shape horizontal wellbore intersecting a two-layer reservoir with cross-flow, a horizontal or inclined well in a three layer reservoir with cross flow and a vertical well intersecting a two-layer reservoir without cross flow. Special attention was paid to the influence of the wellbore inclination angle, the distance from the wellbore to the different boundaries and the permeability ratio.
The Application of New Centralizer Types to Improve Zone Isolation in Horizontal Wells
Authors: Kinzel Holger , Martens James G.
Published: December 2007

Horizontal Drilling has become a commonly used technology to increase the productivity index of single wells and to increase the recovery factor of entire fields. A rising number of horizontal liners are cemented and perforated to be able to solve production problems, such as water and gas coning.

Cementation of a horizontal liner requires extensive planning and engineering. One of the important issues for mud removal is good string centralization. New types of centralizers designed specifically for the application in horizontal well applications have successfully been used in horizontal wells worldwide. Selection criteria for both types of centralizers, bow-type and rigid, and a comparison of their main parameters based on mathematical modeling, are described.
Analysis and Modeling of Fractured Reservoirs
Authors: van Dijk Janpieter
Published: December 2007

The analysis and modeling of fracture and fault patterns on various scales has obtained a major role in hydrocarbon exploration and development. Mainefforts regard the optimization of well bore orientations with respect to fracture network characteristics, the identification of well site locations inorder to enhance productivity, and the improvement of the estimates ofgeometrical parameters such as matrix block sizes and shapes (sigma factor), representative elementary volumes (REV), and fracture porosity distribution forreservoir evaluation.

A number of case studies will be presented regarding exploration and production activities in various types of naturally fractured reservoirs with poor primary matrix permeability. The new techniques developed relate to theissues of predicting parameters such as location, density, interrelation and orientation of fracture sets in complex tectono-stratigraphic settings.

The optimum location and deviation of an exploration well to be drilled canbe established by applying Fracture Potential and Domain Mapping technologieson elaboration's of high quality 3D seismic datasets (amplitude, geometry, coherency), calibrated with available (oriented) core and log datasets(conventional logs, borehole viewers, borehole shape analysis, etc.). Theoutcome of these methodologies are a series of maps which predict fracturedensity and orientation throughout prospects and reservoirs, which can be used to choose optimum locations for exploration and development wells for which fracture and fault orientations can be predicted. Furthermore, strike domaininterference can help in the detection of fluid flow paths and can give clues to the interpretation of well behavior. Combinations of deterministic and probabilistic three-dimensional modeling of the subseismic fracture zone network provides a sophisticated tool to investigate the tectonic texture of the rocks to be drilled, for which fracture orientation can successfully bepredicted.

The remarkable accuracy with which the texture of the fracture network can be analyzed, modeled and predicted applying a range of new technologies is highly encouraging and opens a whole new perspective for challenging future objectives related to the exploration and development of naturally fractured reservoirs.

P. 31
Effects of Rock Heterogeneities on Capillary Pressure and Relative Permeabilities
Authors: Mannseth T. , Mykkeltveit J. , Nordtvedt J.E. , Sylte A.
Published: December 2007

The absolute permeability of a core plug may be heterogeneous and anisotropic, e.g., due to small-scale laminae or cross bedding. Standard methods for determination of the two-phase flow functions, capillary pressure and relative permeabilities, assume a homogeneous and isotropic core. In the implicit method, where a simulator is used to history match the measured data, heterogeneity and anisotropy can be accounted for.

In this paper, the importance of accurate modeling of heterogeneities for the determination of the two-phase flow functions is addressed. Several l-D and 2-D permeability distributions with realistic permeability contrasts are utilized to investigate into the effects of rock heterogeneities on the inferred flow functions.

P. 67
Successful Shale Drilling Using a New Environmentally Compatible Potassium Carbonate/Polymer/PolyGlycol Mud System: Design and Field Experiences
Authors: Mascarà S. , Vallorani F. , Jachnik R. , Formisani D.
Published: December 2007

This paper presents laboratory data and field application results on a new water based mud system which utilizes Potassium Carbonate, a special polymer formulation and a polyglycol. The surfactant properties of the polyglycol around it's cloud point, the existence of normal force and extensional viscosity in the mud prepared under low shear, and the successful application of the mud system in southern Italy to drill massive shale sections with high kaolinite clay content are all discussed.
Unique ESP Completion and Perforation Methodology Maximises Production in World Record Step-out Well
Authors: Blosser W. , Davies J.E. , Newberry P. , Hardman K.
Published: December 2007

This paper describes the key planning and operational experiences gained during the perforation and completion phase of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. The paper presents an overview of how the M- 11 well was successfully completed and describes how a combination of existing technology and new technology has been applied to achieve Wytch Farm's most prolific producer to date.

Well 1M-11SPy (M-11) holds the world record for the highest horizontal departure, 10114m, at any vertical depth, and a record departure: to true vertical depth (TVD) ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESPs).

A new technique for perforating the well was developed to maximise inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with the associated operational issues.

The large departure required the ESP to be set at 8625m, another world record, with the 1000 HP motor requiring a new 7kV cable system and a 1500 kVA variable speed controller (VSC) at surface. This paper describes the background of VSC selection and the physical testing of the complete ESP/cable/VSC system that was conducted prior to installation to ensure that sufficient torque could be generated at the ESP for a range of start-up and operating conditions, and to configure the new type of VSC used for optimal system performance.

The paper reports experience gained, and reviews lessons learned.

P. 579
Intelligent Completion Systems --The Reservoir Rationale
Authors: Jalali Y. , Bussear T. , Sharma S.
Published: December 2007

Two reservoir displacement scenarios are analyzed, wherein control of downhole flow conditions has a marked effect on production performance. The first relates to depletion of a two-layer gas reservoir disposed toward development of crossflow, and the second relates to control of the injectivity profile in a rate-sensitive waterflood. For each scenario a conceptual control architecture is proposed, and the impact of this architecture on production performance is assessed.
Production-Induced Compaction of Sandstone Reservoirs: The Strong Influence of Field Stress
Authors: Hettema M.H.H. , Schutjens P.M.T.M. , Verboom B.J.M. , Gussinklo H.J.
Published: December 2007

During the production of sandstone reservoirs, changes in the pore pressure causes changes in the stresses acting on the reservoir. Reservoir compaction is usually determined by assuming uniaxial strain conditions, i.e. no lateral strain during depletion. Field data of the Groningen gas field indicate that the stress development of the field deviates significantly from the stress path defined by uniaxial strain conditions. Laboratory experiments performed on Groningen core samples show that the applied stress path has a strong influence on the depletion-induced compaction behaviour. We discuss the consequences of these results for the field compaction behaviour by considering the responsible mechanisms. Our findings bring the laboratory derived compaction in line with the in-situ measured field compaction.

P. 547
4D Seismic Interpretive Processing: Optimizing Differential Imaging For Reservoir Monitoring
Authors: Burns C. Scott
Published: December 2007

Data from four repeated 3D seismic surveys over the Oseberg Field will be used to demonstrate the concept of 4D interpretive processing: To optimize 4D processing parameters & methodology and to gauge their cost effectiveness & sensitivity to mapping changes in reservoir properties, it is critical to incorporate analysis of reservoir dynamics & rock physics. Comparative analysis begins by building a reference of the seismic response-seismic attribute maps & 4D model-based classification-related to estimated changes in reservoir properties due to production. Subsequent cross-equalization, position error analysis, and optimization of amplitude transforms can then be efficiently performed with the objective of improving reservoir differential imagery.

Results from the 4D seismic analysis on the Oseberg data indicate that there is general agreement between differential seismic images and reservoir simulation estimates of volume displacement of oil by gas.

P. 329
Screening Criteria For Evaluating the Development Potential of Remaining Oil in Mature Fields
Authors: Weber K.J. , Dronkert H.
Published: December 2007

Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up as investment targets for reactivation and there is general consensus that modem techniques can lead to additional recovery of between 10 and 20 percent. However, there are many pitfalls which can render an apparently attractive project into an economic failure. This paper will discuss the non-technical screening criteria related to reservoir architecture, accumulation condition and production history.

Mobile remaining oil can be found in a number of predictable locations in reservoirs depending on their structural style and facies.

Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. This leads to four main types with some sub-groups for each of which screening criteria have been derived on the basis of field examples and models. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal side-tracks from existing wells. In addition recommendations are given with respect to data gathering to confirni the presence of economically viable targets.

P. 345
Drag Reducer Performance Measurement-A Scaled-Up Laboratory Test Compared With a Field Trial
Authors: Hamouda A. A. , Strand S. , Johnson A. , Tebboth L.
Published: December 2007

Drag Reducing Agent (DRA) is used in numerous single-phase pipeline systems to reduce operating pressures, increase capacity, and decrease reliance on pumping. For a given pipeline system, prediction of the DRA performance is unreliable. Therefore, a reliable laboratory flow-loop test, the results of which could be scaled-up to the full-scale pipeline, would be valuable.

During transportation, the oil temperature decreases, the rate of decrease depending on factors such as flow rate, insulation, and surrounding medium. It has been shown in our previous laboratory studies that DRA performance, normalized by a function of Re. (f) 0.5, in a non-isothermal system can be 20% below that of an isothermal system. This behavior has shown to be dependent on the characteristics of the oil (e.g. wax appearance temperature, wax content, oil composition etc.).

The above laboratory observations have lead to a method for scaling-up flow-loop test results to enable prediction of the full-scale field data. The subject of this paper is the validation of these scale-up methods. For this validation, flow-loop tests were performed on the crude oil from a well instrument singlephase export pipeline. The loop test results were scaled-up without knowledge of the DRA performance in the actual pipeline. In the loop tests and field trial a range of DRA concentrations were tested for DRA performance, effect of DRA on wax deposition, and the effect of wax crystallization on DRA. The phenomenon of the effect of the DRA on the wax deposition profile, as shown in our previous studies, was confirmed in this test. The scaled-up loop test results agreed with the field measurements to within ±5% for the tested DRA concentration and ± 13% for the extrapolated concentrations.
Influence of Oilfield Chemicals on the Surface Tension of Stimulating Fluids
Authors: Dabbousi B. O. , Nasr-El-Din H. A. , Al-Muhaish A. S.
Published: December 2007

Surface tension plays a very important role in the stimulation of gas wells. A low surface tension is required to reduce capillary forces that trap the aqueous phase in the formation. Accumulation of the aqueous phase near the wellbore area, known as water blockage, leads to a significant reduction in gas production.

An experimental study was conducted to examine the effects of various acids and stimulation additives on surface tension. A Krüss tensiometer (Model K-12) was used to conduct surface tension measurements. Acids examined included: HCl, acetic, citric, formic, and combinations of these acids. Stimulation additives tested included: mutual solvent, short-chain alcohols, corrosion inhibitors, hydrogen sulfide scavengers, iron-control agents, and clay stabilizers. In addition, the effects of three classes of surfactants (nonionic, cationic and anionic) on surface tension of acid solutions were investigated.

The surface tension of acid stimulating fluids is a complex function of acid type, concentration, and additive type and concentration. Acetic and formic acids had lower surface tension values than HCl, especially at high acid concentrations. The surface tension of the organic acids examined depended on the pKa value of the acid. Organic acids with high pKa values had low surface tension values. The surface tension of hydrochloric acid can be reduced by mixing with acetic acid. EGMBE lowered the surface tension of acetic, formic and hydrochloric acids up to 10 wt%. Increasing the concentration of EGMBE above 10 wt% had no significant effect on the surface tension of these acids. The effect of organic acid strength on surface tension diminished in the presence of EGMBE. Short-chain alcohols reduced the surface tension of 15 wt% HCl with the greatest reduction obtained with n-butanol. Citric and erythorbic acids, which are usually used as iron control agents significantly reduced the surface tension of 15 wt% HCl. Ionic surfactants reduced the surface tension of hydrochloric acid more than the two nonionic surfactants tested. The three corrosion inhibitors examined reduced surface tension up to a critical concentration beyond which they had no effect on surface tension. An aldehyde-based H2S scavenger lowered the surface tension of 15 wt% acid solutions at very low concentrations. Clay stabilizers (cationic polymers) did not significantly affect the surface tension of 15 wt% HCl. Addition of a hydrogen sulfide scavenger, a nonionic surfactant or a corrosion inhibitor into solutions of 15 wt% HCl and EGMBE had a small effect on the surface tension of the acid.
Modifying the Proppant Surface to Enhance Fracture Conductivity
Authors: Dewprashad Brahmadeo T. , Weaver Jim D. , Nguyen Philip D. , Parker Mark , Blauch Matthew
Published: December 2007

This paper describes laboratory studies and field testing that demonstrate how surface modification of proppant with polymeric "tackifiers" can improve the fluid conductivity of propped hydraulic fractures. It also identifies and describes several conductivity enhancement mechanisms that result from proppant-surface modification. Molecular simulations identified optimal intermolecular friction factors of the polymeric "tackifiers" that increases the proppant's intergranular friction. Once coated with a tacky surface-modification material, the proppant grain interacts instantaneously with the surrounding particulates resulting in a stabilized proppant bed.

Experiments show that coating the proppant with these tacky polymeric materials hinders proppant settling in aqueous-based fracturing fluid; this characteristic results in better vertical distribution of proppant within the fracture and an increase in pack porosity. Conductivity measurements of proppant packs [in accordance with American Petroleum Institute (API) standards] support this observation and reveal the influence that closure stress plays in the final proppant-pack conductivity.

Testing with a complete fracturing fluid system indicates that improved fluid removal is possible under certain conditions. Extensive field testing supports this conclusion by providing evidence of increased and sustained fracture productivity with faster and more effective well cleanup after water-based fracturing treatments. Because the proppant surface is modified on the fly and requires no additional time for curing, aggressive gel-break schedules and well flowback rates are used. The use of tacky, polymeric surface-modification materials stabilized proppant packs resulting in little or no backproduction of proppant or fines. This paper includes treatment results from formations that were hydraulically fractured with one of these surface-modification agents.
Rock Mechanics Evaluation of Resin-Coated Proppants for Screenless Completions
Authors: Dewprashad Brahmadeo T. , Kuhlman Robert D. , Nguyen Philip D.
Published: December 2007

In screenless completions, the goal is long-lasting, high-strength consolidations that are resistant to production conditions of bottomhole temperature, fluid flow, and stress cycling. This paper presents results from rock mechanics tests that the authors developed to evaluate precoated and "on-the-fly" resin-coated proppants (RCPs) under simulated downhole conditions. Testing procedures are described, and the principles underlying their development are discussed. The paper also compares the performance of different RCPs and relates test results to the chemical and physical changes occurring at the resin coat's molecular level.

Consolidated RCPs were found to have similar Young's modulus values and maintained these values up to about 325°F, above which they dramatically decreased. Each RCP's resistance to creep and stress cycling varied widely. Some RCPs withstood 20 cycles of stress at 200°F without any change in properties. Failure envelopes were created for different magnitudes of confining stress, and the envelopes of individual RCPs also varied widely.

This paper illustrates how rock mechanics tests can be used to evaluate RCPs for suitability for screenless completions and frac-pack stimulations. It also provides guidelines that practitioners can use to evaluate and select RCPs for screenless completions.
Stimulation of Water Disposal Wells Using Acid-In-Diesel Emulsion: Case Histories
Authors: Nasr-El-Din H. A. , Al-Anazi H. A. , Mohamed S. K.
Published: December 2007

Two wastewater disposal wells in a carbonate field in Saudi Arabia suffered loss of injectivity due to severe formation damage. Lab tests conducted on reservoir cores indicated that regular 15 wt% HCl did not form deep wormholes and caused surface wash-out only. A thorough experimental study was conducted to evaluate using acid-in-diesel emulsions to stimulate these wells which had several tight zones. The emulsified acid consisted of 70 vol% of 15 wt% HCl, 30 vol% diesel and an emulsifier (a cationic surfactant). This is the first time emulsified acid has been used to stimulate disposal wells.

Experimental results indicated that the acid-in-diesel emulsion behaved as shear-thinning fluid. The stability of the acid was found to be a function of emulsifier concentration. The reaction rate of the emulsified acid with reservoir rocks depended also on emulsifier concentration at the reservoir temperature (55 °C). Very low reaction rates were obtained at emulsifier concentrations greater than 20 gals/1000 gals were of acid. These results indicated that longer soaking times would be needed to stimulate disposal wells. This is to ensure complete acid spending.

Coreflood results showed that the emulsified acid formed deep wormholes in tight carbonate cores (< 100 md), where the core permeability increased after the treatment. Permeability ratio (final/initial) of reservoir cores exponentially increased with the acid injection rate. The size and number of the wormholes depended on the acid volume, injection rate and initial core permeability.

The acid-in-diesel emulsion (280 cp at 2 s−1 and room temperature) was applied in two wastewater disposal wells. The designed treatment included a gelled acid stage for acid diversion, and an emulsified acid stage to create deep wormholes in the reservoir. The treatment was very successful and the injectivity of both wells has significantly increased.
Dynamic Rheology as a Method for Quantify Gel Strength of Water Shutoff Systems
Authors: Kakadjian S. , Rauseo O. , Mejias F.
Published: December 2007

In this paper the development of a method for rheological characterization to evaluate quantitatively the gel strength of polymeric system used for water shut off of oil wells is shown. Such method was used to determine the viscous and elastic characteristics of three gel systems using the dynamic rheology as a tool. The method allowed to study the general consistency of the gel (G*), the elastic behavior of the consistency (G’) the viscous component of the consistency (G") and the relationship between the two modulus (Tan δ). Three systems were studied, two Polyacrilamide/Chrome III gels and one Polyacrilamide/Organic Crosslinker gel. In one of the two Polyacrilamide/Chrome III gel systems the change of the elastic and viscous modulus with different gelling time was studied. In this system was observed that G’ changed from 0.07 Pa for 0 hours of gelling time up to 289 Pa for 4 hours of gelling time. On the other hand, the same system showed that the change of the viscous component of the gel strength (G") only increased from 5 Pa for 0 hours to 76 Pa for 4 hours gelling. For the other two systems the influence of the level of crosslinking in the viscoelastic characteristics was studied and it was found that Tan δ increased as the crosslinking level decreased. This method would replace the qualitative letter code generally used to classify the gel strength, which will be considered as a more rigorous and exact tool of characterization and would provide better understanding of the behavior of the gels for water shut off.
Controlling In-Situ Gelation of Polyacrylamides by Zirconium for Water Shutoff
Authors: Chauveteau G. , Tabary R. , Renard M. , Omari A.
Published: December 2007

In water shut-off operations, the polymer solution and the crosslinker are currently mixed into surface facilities just before to be injected through the production or injection well and then inside the reservoir. Therefore, the crosslinking system is always subjected to shear stresses while « gelling » and the main question for the operator is the depth of penetration inside the reservoir of the « gelling » system. This paper reports a theoretical and experimental investigation of the process of crosslinking under shear. The model derived from our theoretical analysis predicts that the characteristics which governs penetration in porous media, i.e. viscosity and microgel size, can be easilly calculated from simple shear viscosity measurements. The proposed theory describes the crosslinking under shear as a four successive steps process. By taking into account the break-up of microgels by shear forces as soon as their size reaches a given value, this theory predicts that, under a constant shear rate flow, a solution of monodispersed microgels is obtained at the end of the final step. Using a scaling law approach, we derived a very simple equation linking final viscosity and microgel size to initial polymer characteristics as well as applied shear rate. The final shear stress is expected to be independent of shear rate but proportional to crosslink energy, thus providing a simple way to compare various available crosslinkers. New experimental data, obtained by using a low toxicity crosslinking system, i.e. a weakly hydrolyzed and sulfonated polyacrylamide together with zirconium lactate are reported. All the predictions of our model are in agreement with our own data, as well as with others found in the literature. In addition, new information on the physicochemistry of the acrylate-lactate-zirconium system is obtained. While increasing pH results only in a retardation of the crosslinking process without changing crosslink energy, both a retardation and a weakening of crosslinks is obtained by adding sodium lactate. Injectability experiments in porous media involving the injection of both the polymer and the crosslinker, mixed just at the entrance of the porous medium results in a strong plugging after a given time. On the contrary, the injection of preformed microgel solutions, does not show any plugging tendency, although giving higher mobility reduction in agreement with the proposed theory.