bluuebunny/crossref_metadata_2025 huggingface dataset:
Results of Thermal Horizontal Completions with Sand Control in Lake Maracaibo, Venezuela: Case Histories of Horizontal Gravel Packs in Bachaquero-01 Reservoir
Authors: Pizzarelli S. G. , Gonzalez O. E. , Justiniano P. , Olivares S. A. , Potma J. J.
Published: December 2007

The heavy-oil reservoir Bachaquero-01, in the Lagunillas district of Venezuela's Lake Maracaibo, has been productive since 1934. Because the oil gravity is only 12° API, steam has been injected since 1971 to increase production. To further optimize production, stand-alone horizontal wells have been drilled since 1996. However, in only 4 months after steam was injected into the horizontal wells, a very fast decline of up to 50% of initial production was observed in these nongravel- packed wells.

In a drilling-and-completion campaign from October 2000 to January 2001, 18 horizontal wells were successfully drilled and gravel-packed. In this paper we describe the gravel-pack techniques applied to minimize the rapidly declining rate of production in horizontal alternate steam-injection wells. We explain the method used for screen and gravel-size selection and summarize the completion operations and gravel-pack fluids that were used. We describe the modification of an existing hydraulic packer with a high-temperature seal of 600°F—a combination used for the first time worldwide. Finally, we illustrate the successful drilling-and-completion campaign with case histories and production performance.

The gravel-packed wells had an average increase of 15% productivity after 1 year with no sand production. The gravel- pack operations were executed at a pump rate of 2 to 3 bbl/min with a sand concentration of 0.5 to 0.7 pounds of proppant per gallon added (ppa), observing continuous fluid returns of 50% to 80%. The packers were successfully field tested after a period of three weeks of steam injection.
Implementation of Advanced Cementing Techniques to Improve Long Term Zonal Isolation in Steam Assisted Gravity Drainage Wells
Authors: Stiles David , Hollies Doug
Published: December 2007

Steam Assisted Gravity Drainage (SAGD) development of the Athabasca oil sands has led to a unique approach to horizontal drilling combining many existing and new technologies. From a cementing perspective, preventing degradation of the cement sheath due to induced stress cracking and preventing gas migration are the two main challenges that must be addressed in order to achieve the objective of long-term zonal isolation across the length of the wellbore.

One of the main functions of cement is to prevent fluid communication between formations or to surface throughout the life of the well, including after abandonment. Even when cementing operations have provided a good initial hydraulic seal, changes in downhole conditions can induce stresses to destroy the integrity of the cement sheath resulting in a loss of zonal isolation. Changes in downhole stress conditions that occur during the life of a SAGD well are particularly extreme. Stresses in the cement sheath induced by extreme temperature cycling can result in severe mechanical damage and ultimate failure of the cement sheath, potentially leading to leakage of steam from the reservoir. Along with the requirement of maintaining cement sheath integrity, special cement design and placement considerations must be taken to prevent annular gas influx and migration. Annular gas migration prior to the setting of the cement can lead to channels that would not only provide a pathway for gas but also a potential conduit for steam to escape into shallower zones or to surface.

A new approach to cement design was undertaken to fulfill the requirements of cementing PanCanadian's (now EnCana Corp.) SAGD wells in Christina Lake. A cement system with improved flexibility to resist stress cracking was designed and implemented. This system is engineered to have a low Young's Modulus while maintaining high compressive and tensile strengths as compared to conventional cement systems. The permeability of the set cement is very low, yielding a material that is highly resistant to attack by corrosive fluids. Finally, the system is designed to be gas tight to prevent gas migration. This paper presents data on the new cementing techniques and technologies used as well as case history results on the six wells cemented at Christina Lake.
Feasibility of Fluid-Jet Based Drilling Methods for Drilling through Unstable Formations
Authors: Gupta A. , Summers D. A. , Chacko S. V.
Published: December 2007

This paper presents the development of fluid-jet methods for the drilling of wells through unstable formations. The work demonstrates the technical capabilities of drilling through unstable formations including Methane hydrate and permafrost.

Abrasive fluid-jet systems are capable of drilling through rocks of all types, and with greater directional control that is not susceptible to the geologically induced deviations encountered with mechanical bits, since no mechanical contact is made with the rock while drilling. Abrasive fluid-jets drill rock through the erosion induced by very small particles which individually remove only small fragments but are in such numbers that the drilling rate is at or above that of conventional tools. The particles are powered by the velocity of the supporting fluid, generated in turn by pumps on the surface. The cutting occurs ahead of the nozzle body allowing a casing to be used which is of a larger diameter than the drilling assembly itself. Abrasive jets drill through the erosion of the rock under the specific impact point of the jet contact. They do not therefore exert significant force to the rock around the drilling point and erode the rock without inducing great disturbance to the surrounding material, thus enhancing borehole stability. Fluid-jet methods have the potential of improving drilling efficiency through unstable formations.
The Fourth Horizontal Project in the Mature Algyõ Field
Authors: Pipicz V. , Benedek L. , Palásthy Gy. , Báródi T. , Blahó J. , Joshi S. D.
Published: December 2007

Since 1993, about 70 horizontal wells, have been drilled in three different successful projects. These projects were implemented in the mature Algyõ field. A fourth project, consisting of more than 20 new horizontal sections, kicking off existing abandoned wells, has been developed for the thin oil rim present in two high permeability reservoirs with top gas and bottom water The main difference between the two reservoirs is that one has water injection and the other has two layers with strong natural bottom water drive.

The first experimental wells of the 4th project were drilled to minimize the coning effects and to increase the areal recovery efficiency in the initially 9 and 6 m thick oil zones (shrinked to 4 and 3 m in the recent state of exploitation).

To decision about the project implementation was based on reserve re-evaluation. The re-evaluated reserves were determined using results of the experimental wells, a 3D geological model, a full field 3D simulation and horizontal well production matches with JTI software. To define saturation, neutron logs were used to determine for the gas-oil contact and carbon-oxygen logs are used for monitoring the oil-water contact (because of the very low salinity of formation water). The target zone of the horizontal sections is +/− 0.5 m vertically and very detailed information analysis is required to plan proper trajectories.

The recent state of the project, the evaluation, methods and simulation process used for the decision- making are presented in the paper.
Alternate Fuels for Thermal Projects
Authors: Garnier O. F. , Cupcic F.
Published: December 2007

Heavy oil developments in the Athabasca area require large quantities of steam, and this becomes a major expense when natural gas is used in Once Through Steam Generators. This paper reports on an exploration of possible ways to reduce these costs by using alternative fuels obtained from an integrated upgrader.

Depending on the upgrader selected, associated waste streams are produced such as petcoke, asphalt or unstable vacuum residue from which little or no value can be drawn in the Athabasca area except by exploiting their heating value. Combustion of these waste streams is not technically a problem, but the cost of using an alternative fuel is strongly impacted by the specific water treatment required and the problem of sulphur oxide emissions.

Present configurations for heavy residue boilers require high-quality demineralised water, and the related water treatment represents a higher cost than for the partly softened feed water used in conventional Once Through Horizontal Steam Generators (OTHSG). Combustion of high sulphur fuels calls for an efficient desulphurisation method in order to meet the increasingly stringent statutory emission limits. Traditional methods using limestone involve injection and the problematic disposal of large quantities of solids.

This study has characterised four types of upgrading residues, namely petcoke, asphalt, unstable vacuum residue and heavy crude oil, in terms of their nature and sulphur content. It has determined for each fuel the appropriate boiler configuration, including flue gas depollution and water treatment, and compared its cost with that entailed in the common practice of producing steam with natural gas in Once Through Steam Generator (OTSG) field units. Regenerable SO2 scrubbing techniques coupled with Claus units have been investigated, as possible means of producing pure liquid or solid sulphur. By converting upgrading residues into syngas by partial oxidation, cleaning up the syngas by removing its sulphur and sending the clean syngas to OTHSG unit, both the water treatment requirements and the SO2 emission limits can be met. The cost of such a solution has been compared to that of direct combustion of residues in a boiler.
Heavy Acidic Oil Transportation By Emulsion In Water
Authors: Verzaro F. , Bourrel M. , Garnier O. , Zhou H. G. , Argillier J-F.
Published: December 2007

This paper sets out to demonstrate, at lab scale, the feasibility of the two main phases of the process, namely the emulsification of a heavy Venezuelan acidic crude oil (ZUATA), and the subsequent breaking of the oil-in-water emulsion.

The heavy ZUATA crude can be emulsified directly by making use of the surfactants naturally present in this rich acid oil. These potential surfactants, mainly represented by naphthenic acids, become effective emulsifiers when salified into naphthenate anions by the addition of bases (soda, ammonia).

Stable oil-in-water emulsions, typically with 60 to 65% oil, are obtained by using these two bases. There are a number of advantages to be gained in using ammonia to form the oil-in- water emulsions as opposed to other bases (soda for example) for emulsion breaking and phase separation.

The paper demonstrates that it suffices to heat the emulsion to break it. It describes the conditions required for ammonia removal and recovery, and the resulting emulsion breaking.

An industrial process for achieving the separation is then proposed.
Innovative Design Allows Construction Of Level 3 Or Level 4 Junction Using The Same Platform
Authors: Desai Praful , McGarian Bruce
Published: December 2007

The simple and most economical multilateral option in the production of heavy oil with optimum solids control is to employ either level 3 or level 4 junctions to access and drain oil bearing sand bodies.

This paper presents an innovative junction design which when fully deployed, can be left as a level 3 construction, or it can be turned in to level 4 by conventionally cementing the junction. In practice the isolation provided with the level 3 construction far exceeds the capabilities of conventional alternatives, and when cemented as a level 4, provides a junction with stability beyond that afforded by conventional methods. In either scenario, access to the main bore below the junction and to the lateral bore is maintained.

Once the junction is in place, conventional completion equipment can be run after drilling the lateral to facilitate the production.

In addition, this innovative junction offers other advantages. Among those are, (1) Milling or washover of excess liner is not required when constructing a level 4 junction because there is no excess liner left in the main bore during the junction construction. (2) The lateral liner can be deployed simultaneously with the junction for both level 3 and level 4 junctions. (3) The platform allows full re-entry capability into main and lateral bores in a single or stacked junction configuration.

The paper will also discuss in detail, recent field installations and developments of this innovative design in level 4 complexity in 9-5/8" 40 lb/ft casing.

Major system components and their functions are described, as well as running procedures and lessons learned.
Chemical Removal of Organic Foulants from Produced Water Recycled as Steam
Authors: Hart Paul R.
Published: December 2007

A limitation on the use of produced water as steam to assist oil recovery by gravity drainage (SAGD) from oilsands is the presence in the water of boiler foulants. Ordinary water clarification treatments were found to leave behind certain classes of organics that shorten boiler cycle times. Using molecular probes to compare produced water from SAGD processes having different rates of boiler fouling, an unstable class of organic colloid was identified, and a new chemical treatment developed to remove it.
An Inexact Air Quality Model for Petroleum Pollutants Based on Techniques of Factorial Analysis and Stochastic Simulation
Authors: Zou Yun , Li Jianbing , Huang G. H. , Li Hengliang
Published: December 2007

In this study, an inexact air quality modeling system is developed to predict the maximum ground level concentration (MGLC) and distance to MGLC (DMGLC) of gaseous pollutants from point sources in petroleum operations. The influence of uncertain parameters is evaluated through an integration of 2k factorial analysis and stochastic simulation. The results can provide useful information for risk assessment and decision analysis.
Innovative Use of the Well Freeze Technique for Repairs on Steam Injection Wells in a Thermal Recovery Project
Authors: Zatka M. J. , Foutz T. , Finley D.
Published: December 2007

Although isolation of lines and wellheads using ice plugs is not new in itself, the liquid nitrogen approach developed for use on Aera Energy LLC’s ("Aera’s") Diatomite Steam Drive steam injection wells offered several creative and novel aspects. The procedure was first thoroughly shop-tested and then field-tested on two wells. Bentonite gel was used as a plugging agent due to its rheological characteristics and low thermal expansion compared to water. The gel was mixed to ensure sufficient viscosity to remain in place once spotted across the freeze interval. Cooling was applied by circulating cold nitrogen gas through copper tubing wrapped on the outside of a 13⅜" surface casing string. Contact temperatures on the surface of the external casing were closely monitored to ensure they were never lower than approximately –100°F throughout the process to minimize risk of casing embrittlement.

At 12 hours or less on each well, the time to form ice plugs to the core through a multiple string completion and two cement layers was very manageable. All seven injection strings above the wellhead on the two test wells were safely cut off, and each string fully converted to the desired new injection configuration above the casing bowl.

Thorough safety and technical planning prior to the field trials, creation of several new tools to assist with various program steps, and identification / consideration of contingencies helped in avoiding mistakes, encountering difficulties during the job and, ultimately, making the trials a thorough success.
Opportunities of Downhole Dielectric Heating in Venezuela: Three Case Studies Involving Medium, Heavy and Extra-Heavy Crude Oil Reservoirs
Authors: Ovalles Cesar , Fonseca Anyaleth , Lara Ali , Alvarado Vladimir , Urrecheaga Kerin , Ranson Aaron , Mendoza Humberto
Published: December 2007

The use of electromagnetic radiation, radiofrequency (RF) and microwaves (MW), for downhole dielectric heating has potential applications in enhanced/improved oil recovery processes (EOR). The Lambert’s equation was coupled to a commercial simulator in order to model reservoir dielectric heating. Using a MW heated (2.45 GHz) one-dimensional reactor, this mathematical model was validated in the presence of crude oil/sand cores. Three different conceptual reservoirs were evaluated which involved a medium crude oil (24°API), a shallow (1100 ft) Lake Maracaibo heavy oil (11°API) and a thin pay zone (20 ft) Orinoco Basin extraheavy crude (7.7°API). For all the cases evaluated, numerical simulation results showed an important acceleration in the oil production due to RF and MW heating which was attributed to reduction of crude viscosity coupled with favorable relative water-to-oil permeabilities. For example, in the shallow heavy oil case, RF heating led to an increase of 86% of the cumulative oil production in comparison with the cold production case, using 140 MHz at 50 kW over a ten-year period. Furthermore, calculated energy gains (measured as the ratio between the energy extracted as crude oil equivalent to energy added to the reservoir as electricity) were in the 8 to 20 range, indicating that the process is favorable from the thermodynamic point of view. These conceptual numerical simulation results indicate the high potential of dielectric heating technology for medium, heavy and extra-heavy EOR with possible field applications.
Long-Term Performance of Multilaterals in Commingled Reservoirs
Authors: Yildiz Turhan
Published: December 2007

In this study, a comprehensive transient model was developed for multilateral wells producing from multiple formations separated by impervious streaks. Model is flexible and is capable of simulating the flow with any number of layers, unequal initial layer pressure, non-uniform petrophysical properties for each layer, and unequal layer size. Additionally, each lateral can have nonuniform formation damage and may be selectively completed.

We investigated the long-term rate decline and cumulative recovery response of the multilateral wells connecting multiple isolated formations. Total flow rate, cumulative production, and fractional rate for each branch, are all compared for several completion scenarios and layer properties. Crossflow between the layers through the wellbore is also evaluated.
First Horizontal Well Opens New Gas Opportunities in the Sierra Chata Field, Neuquén Basin-Argentina
Authors: Sanz C. A. , Nilson G. J. , Acree J. F. , del Pino M. , Anaya L.
Published: December 2007

The first horizontal re-entry gas well was successfully drilled and put on line in the Sierra Chata field in the Neuquén basin in Argentina. This article compares the model forecast with the results obtained. The objectives were: (1) to add gas reserves and (2) to incorporate horizontal technology that will allow access thin or low permeability sands, in remote areas that would be economically marginal with vertical wells.

Recent interpretation of 3-D seismic and geologic data indicated that the "D" Sands were better developed to the northwest of the vertical well SCh-17. In order to access gas reserves postulated to exist there, it was planned to drill a horizontal re-entry well utilizing the existing vertical well, SCh-17 as a re-entry conduit. From the well SCh-17 a re-entry was made at 244 m from the deviation point (KOP) in 1600 m MD, drilling slightly up-dip to 2975 m MD, using with a downhole motor and a MWD logging system.

Shale-silt lithologies within the sand members affect the vertical transmissibility (TZ) between the "D" Sand members. Sensitivity runs were made using a reservoir simulator built to test the effect of such variables on the horizontal well productivity. For the most probable case, an initial flowrate of 17.7 MMscfd (502 Mm3/d) was predicted. A final cumulative production of 7.3 BSCF (206.7 MMm3) of gas was predicted by the numerical simulation model.

Three years of production history confirmed the forecast and assumptions made in the well proposal and also encourage new horizontal prospects.
Fault Interpretation Strategy for 3D model Simulation
Authors: Mendoza P. , Floricich M.
Published: December 2007

Advances in computing technology have allowed the development of sophisticated 3D cellular modeling and visualization software, which has found a variety of applications in the oil industry. This technology includes spatial attribute modeling and the visualization of hydrocarbon reservoirs to improve the understanding of the geological structure including internal features and the distribution of formation properties.

This paper discusses experiences gained in building a geological model for the LL-03 reservoir (in this reservoir there is a horizontal well drilling strategy) and the subsequent manipulation and transfering of this data into a 3D reservoir simulator for initialization purposes.

The paper covers the modeling of fault planes in complex reservoirs, the handling of both vertical and sloping fault surface and the distribution of petrophysical properties (porosity, permeability and water saturation) of the geological model to be used in the reservoir simulation.

The technique presented here differs considerably from the traditional method for fault interpretation. This new method consists in interpreting the plane that describes the fault in the space, using several techniques that allow defining the structural framework. Advantages for both, geocientists and reservoir engineers in displaying and reviewing the 3D image of the fault planes and the reservoir at an early stage in the project are discussed.

The paper concludes with suggestion for developments of the workflow to create the most realistic fault plane according to the structural framework to further enhance the effectiveness of the present 3D modeling method.
Downhole Conversion of Lloydminster Heavy Oil Using THAI-CAPRI Process
Authors: Xia T. X. , Greaves M. , Werfilli W. S. , Rathbone R. R.
Published: December 2007

THAI - ‘Toe-to-Heel Air Injection’ is a radically new process for the recovery and in-situ upgrading of heavy/medium crude oil and bitumen. It is an integrated-horizontal wells process, which creates its own natural sealing mechanism (in the horizontal producer well), enabling stable combustion front propagation along the horizontal producer well to be achieved. CAPRI is an extension to the basic THAI (thermal) process, which involves the emplacement (‘gravel-packing’) of a standard refinery HDS catalyst, around the horizontal producer well.

A series 3-D combustion cell experiments were performed to physically simulate the THAI-CAPRI process, using Lloydminster heavy crude oil (11.9°API). In separate THAI and CAPRI experiments, high temperature combustion was sustained (500-550°C), achieving stable combustion front propagation. Very high oil recovery was achieved, exceeding 79 % OOIP for THAI and CAPRI. The first-stage of downhole conversion, or in-situ upgrading, is accomplished by thermal cracking (THAI), and thermally/catalytically, in the second stage (CAPRI). Thermal upgrading of the produced oil by THAI averaged 18.3 °API - an incremental conversion gain of 6.4 API points, with a maximum of 22 °API. Higher upgrading was achieved by CAPRI using a regenerated CoMo HDS catalyst. The produced oil averaged 23°API, essentially a light oil product. The oil viscosity produced by THAI or CAPRI was as low as 20 to 30 mPas.
Evaluating Productivity of a Horizontal Well
Authors: Michelevichius D. , Minijos Nafta , Zolotukhin A. B.
Published: December 2007

This paper discusses an alternative approach to a horizontal well (HW) productivity evaluation. The approach is based on the exact solution to a task of the horizontal well productivity evaluation in a 3D reservoir with correct evaluation of all boundary conditions including the no cross-flow conditions at the top and bottom of the reservoir.

Validation of the new equation for the HW productivity is made by means of special asymptotic analysis. In particular, it is shown that the obtained solution asymptotically approaches well-known solutions for cases of simple flow geometry.

However, comparison of the new equation with solutions available from the literature shows some differences between them. We believe that this is mostly due to a more accurate handling of boundary conditions in the new solution. For example, comparison with Joshi’s solution [1, 2] shows that a newly obtain solution gives higher production rates for short length of horizontal sections (L in the order of tens of meters) and lower rates for long horizontal wells in thin reservoirs (Lπh, L⊇re). In the latter case reduced production rate (as compared with [1]) was obtained with due regard for a no cross-flow conditions at the top and bottom of the pay interval. Higher production rates in case of short length of horizontal sections can be caused by a dominating effect of 3D flow in the vicinity of a well, especially in case of a thick pay interval. The highest discrepancy between solutions reported in the literature and proposed in this paper found to be up to 19% for long wells and can exceed 30% for short sidetracks (5-20 m). More detailed analysis of similarities and differences between several solutions is given in the next sections.

A generalized solution for the inflow performance of a HW accounting for the directional values of the reservoir permeability (an orthotropic reservoir) is also given in the paper. In particular, it is shown that in case of anisotropic reservoir orientation of a horizontal well in plane has a strong impact on its productivity
Pressure Pulse Workovers in Heavy Oil
Authors: Dusseault Maurice , Shand Darrell , Davidson Brett
Published: December 2007

Approximately 100 pressure pulse workovers have been performed on heavy oil wells in Canada since 1998. Analysis of a number of the wells shows varying degrees of success, but in general, the workovers have paid for themselves in almost all recent cases. Although there is insufficient information to fully prove hypotheses using statistical criteria, it appears that pressure pulse workovers have particular application in three situations: ▪In cases where the CHOPS well did not initially start producing sand during the primary completion attempts;▪In cases where the well became disconnected from the far-field pressure and gravity driving forces; and,▪In cases when it is desired to place a workover chemical in a well-dispersed fashion around a well.

This article will review the physical mechanisms and drive energy sources that are believed to be responsible for CHOPS production; it will also present the physical processes that we believe occur during aggressive pressure pulse workovers around a heavy oil well.
Determining Oil Sand Reservoir Properties from Logs and Core – The Controversy Continues
Authors: Donnelly John K. , Hitchner John
Published: December 2007

It has been 25 years since Zwicky and Eadc presented their paper on the subject. Now that the Steam Assisted Gravity Drainage (SAGD) process has made it possible to open much of the oil sand resource to commercial development the controversy is renewed. The key reservoir properties that must be determined from log and core data are porosity, permeability and initial water saturation. This paper will review an approach that has been successful for the authors. An example of the use of this method for predicting the performance of a SAGD application is given.
The Long Lake Project – The First Field Integration of SAGD and Upgrading
Authors: Kerr Rich , Birdgeneau John , Batt Bob , Yang Peter , Nieuwenburg Gary , Rettger Phil , Arnold Jim , Bronicki Yoram
Published: December 2007

The OPTI Canada Inc. (OPTI) / Nexen Inc. (Nexen) Long Lake integrated bitumen recovery and upgrading project is a unique solution to the three key problems associated with the development of thermally produced extra heavy oil resources: the low value of the produced oil, the high fuel cost associated with thermal production, and the need for diluents to transport the produced oil to markets. The Long Lake Project will produce a premium light sweet synthetic crude from steam assisted gravity drainage (SAGD) produced Athabasca bitumen, utilizing upgrader bottoms as the primary source for upgrader hydrogen and SAGD fuel.

The core of the Long Lake integrated upgrader is the patented OrCrude™ upgrading process that uses distillation, solvent deasphalting, and thermal cracking in a unique combination to partially upgrade bitumen into OrCrude product and produce an asphaltene by-product.

At the Long Lake Project the OrCrude process will be integrated with commercially proven technologies to hydrocrack the partially upgraded OrCrude product to premium synthetic crude. In addition, the asphaltenes will be fed to an asphaltene gasification system to produce hydrogen for the hydrocracker and syngas fuel for the SAGD process.

The result is an integrated project that will produce premium synthetic crude with quality characteristics that are superior to other synthetics, at an operating cost that is less than any other Canadian production and upgrading project. The capital cost for the integrated Long Lake Project is forecasted to be comparable to other integrated Athabasca bitumen and upgrading projects.

The OrCrude process has been demonstrated at a 500 bpsd commercial demonstration facility near Cold Lake, Alberta which has been operating since mid-2001 on Cold Lake and Athabasca bitumens. The Long Lake Project, currently in the regulatory review process, is proposed to have an initial size of 70,000 bpsd of SAGD production and 70,000 bpsd of upgrading. OPTI and Nexen have plans to subsequently expand the upgrader to 140,000 bpsd. Construction is planned to commence in late 2003 with production in 2006.
Good Engineering Practices Achieve a 30-Fold Increase in Injection Rates in Selected Niger Delta Reservoirs
Authors: Arukhe James , Nwoke Linus , Uchendu Chike
Published: December 2007

Key points of the successful implementation of a pressure maintenance scheme by water flooding in a major operator in Nigeria are presented.

The wells considered were completed in July / August 2001 and immediately put on stream. They were designed to dump circa 7,500 BW/D from the sands at ±6100 feet TVD to an aquifer nearby. An initial dump rate as low as 200 BW/D (average) at a maximum surface injection pressure of 1000 psi was recorded prior to the jobs. This was attributed to severe impairment from the pseudo-oilbased mud, incompletely removed with stimulation treatments following perforation. Low permeability or wellbore damage associated with the mud in the drilling phase may also have been responsible for limiting injection rates into these sands, especially if the perforation tunnels during completion, did not extend past the area of mud invasion.

The stimulation treatments used a xylene solvent pre-flush and a new HF acid treatment to remove the pseudo-oil and perforation debris damage, improving injection rates significantly. The more than 30-fold injectivity improvements that resulted may have been due to one or a combination of the following:A nitrified acid-aromatic pickle performed before pumping treatment fluid into formation.Pickle volume kept at approximately 25% tubing volumeTreatment performed in segments reciprocation across the perforationsInjection lines flushed to more than expected injection rates to ensure clean injection water.Circulation of tubing to clean water using foamed nitrified fluids during the pickle, helped to bring the spent pickle acid back to surface.

Remedial work to further improve the dump rate (and oil sweep) may only be considered if BHP surveys at a future date from closed in wells do not indicate reservoir pressure stabilization or an improvement over the decline previously observed.

Introduction

The KKK field is an areally extensive field located in a Swamp location in Niger Delta. The field was discovered by KKK-1 well in 1996 and completed in August 2000 as a dual string water injection well in two (2) major aquifer sands (upper and lower reservoirs), one on each (short and long) string. Following this, several other wells have been completed to develop the field. A reservoir study was conducted for the upper and lower reservoir sands to investigate the need for pressure maintenance and artificial lift to maximize oil recovery from the reservoir. This study, supported by the geological interpretation of limited aquifer extent, showed that pressure maintenance by means of peripheral water injection was required to maximize oil recovery efficiency. The water injection wells were therefore needed to restore reservoir pressure so that oil recovery is maximised and GORs are reduced.
Rigless Activities at Otumara in the Western Nigerian Swamp
Authors: Hijlkema Sjouke
Published: December 2007

"Snubbing" and "Hydraulic Workover Unit (HWU)" are words not often heard in Shell operations, unless used for special projects. However, they do serve a good purpose when used correctly. In an environment where rigs are expensive and attract many "disturbances" by communities, they can be used as an effective alternative to well workovers.

The Hydraulic Workover Unit supplied by an indigenous contractor is in line with the drive to support local contractors in developing expertise in the areas of well completion, work over and abandonment. The current arrangement is for the indigenous contractors to work under the umbrella of a multinational company such that in time they can become autonomous.

These considerations were the main driving factors to initiate the "Otumara workover campaign", (to prepare wells for gas-lifting), with a HWU instead of a rig.

This has resulted in potential cost savings of about US6$ million, increased oil production potential by 30-40,000 bbl/day, increased indigenisation of the Nigerian Oil Service industry in Nigeria, and is a prime example of a paradigm shift on "how to do things differently".
Generation of Low-Order Reservoir Models Using System-Theoretical Concepts
Authors: Heijn T. , Markovinovic R. , Jansen J. D.
Published: December 2007

We present five methods to derive low-order numerical models of two-phase (oil-water) reservoir flow, and illustrate their features with numerical examples. Starting from a known high order model these methods apply system-theoretical concepts, originally developed in measurement and control theory, to reduce the model size. Using a simple but heterogeneous reservoir model, we illustrate that the essential information of the model can be captured by a very limited amount of state variables (pressures and saturations). Ultimately we aim at developing computationally efficient algorithms for history matching, optimization and in particular the design of control strategies for smart wells. In this study we applied 1) modal decomposition, 2) balanced realization, 3) a combination of these two methods, 4) subspace identification, and 5) proper orthogonal decomposition (POD), also known as principal component analysis or the method of empirical orthogonal functions. Methods 1 to 4 result in linear low-order models, which are only valid during a limited timespan. However, the 5th method (POD) results in a non-linear model that remains valid over a much longer period. Subspace identification requires only input-output data and no knowledge of the system itself, and could therefore, in theory, also be applied to measured data. In particular POD and identification are promising methods to generate low-order models.
Experimental Design as a Framework for Reservoir Studies
Authors: White Christopher D. , Royer Steve A.
Published: December 2007

Numerical simulation integrates extensive geoscience and engineering data with complex process models to examine reservoir behavior. Reservoir studies commonly consider many scenarios, cases, and realizations. However, reservoir simulation can be expensive. Complexity, combinatorics, and expense motivate improved reservoir study methods. The experimental design framework selects relevant models, records factor settings for models, creates data files, controls execution, gathers summary data, and creates response models. Response surface models facilitate Monte Carlo simulation, uncertainty analysis, optimization, parameter estimation, upscaling, and performance forecasting. A predevelopment study of a Gulf of Mexico turbidite reservoir uses this framework to examine the sensitivity of oil production predictions to well location, absolute horizontal permeability, pore compressibility, aquifer size, skin, and vertical permeability. Well location is optimized for cases with uncertain parameters.
Higher Dimensional Wave-Oriented Upwind Schemes With Minimal Cross-Wind Diffusion
Authors: Edwards Michael G
Published: December 2007

Standard single-point upstream weighting schemes are still the most common type of method in reservoir simulation for integrating the essentially hyperbolic components of the system. These schemes rely upon upwind information that is determined according to the grid geometry. As a consequence directional diffusion is introduced into the solution that is grid and geometry dependent. The effect can be particularly important for cases where flow is across grid co-ordinate lines and is known as cross-wind diffusion. A new type of upwind scheme is introduced to reservoir simulation that minimizes cross-wind diffusion, is free of spurious oscillations and remains locally conservative.
Coupled Geomechanical Simulation of Stress Dependent Reservoirs
Authors: Stone Terry W. , Xian Chenggang , Fang Zhi , Manalac Evangeline , Marsden Rob , Fuller John
Published: December 2007

A geomechanics option that features the three dimensional elastoplastic stress equations which are fully or partly coupled to a commercial reservoir simulator is applied to a field and a synthetic case. Sanding, fracturing and stress dependent flow are analysed.

First the basic formulation is discussed. Elastic stress equations and boundary conditions are described including their implementation in the finite difference simulator. Comparison is made with an industry standard finite element code with an option for coupled single phase flow. It is demonstrated that the finite difference implementation of the stress equations, which is second order, can produce acceptable accuracy when compared against finite element simulators. Non-orthogonal corner-point gridding is also reviewed in this context when the gridding is skewed. Some features of other gridding types including unstructured grids are also presented. Plasticity, stress dependent permeability and faults are available as options.

Two cases are presented which were designed to demonstrate the applications of sand management, simulation of tight gas reservoirs with stress dependent permeability and propped/etched fractures. The sand management case is based on an offshore gas field. Reservoir geometry, properties and geological (tectonic) details were provided by the operator. A case which simulates fracturing was designed as a tutorial. Although synthetic, it offers a workflow for the use of predicted stress and pore pressure as input to calculations of fracture conductivities/geometries whose output is returned to the simulator.

This geomechanics option is currently under development. Some areas of further work are mentioned.
An Efficient Discrete Fracture Model Applicable for General Purpose Reservoir Simulators
Authors: Karimi-Fard M. , Durlofsky L. J. , Aziz K.
Published: December 2007

A simplified discrete fracture model suitable for use with general purpose reservoir simulators is presented. The model handles both two and three-dimensional systems and includes fracture-fracture, matrix-fracture and matrix-matrix connections. The formulation applies an unstructured control volume finite difference technique with a two-point flux approximation. The implementation is generally compatible with any simulator that represents grid connections via a connectivity list. A specialized treatment based on a "star-delta" transformation is introduced to eliminate control volumes at fracture intersections. These control volumes would otherwise act to reduce numerical stability and time step size. The performance of the method is demonstrated for several example cases including a simple two-dimensional system, a more complex three-dimensional fracture network, and a model of a strike-slip fault zone. The discrete fracture model is shown to provide results in close agreement with those of a reference finite difference simulator in cases where direct comparisons are possible.
Better Field Development Decisions from Multi-Scenario, Interdependent Reservoir, Well, and Facility Simulations
Authors: Narayanan Keshav , Cullick A. S. , Bennett Matthew
Published: December 2007

Making better decisions, which take into account uncertainty in all the components of an exploration and production (E&P) asset's value chain, continues to be a significant challenge for the industry. The literature of the last few years has emphasized the importance of workflows that integrate and include formal quantification of uncertainties across subsurface, well locations, well configurations and operations, surface interconnections, and economics. Much of the effort has focused on scenario and probabilistic analysis decision support techniques. The industry continues to make many field development decisions from flow simulation ‘sensitivity cases’ or from simplified models, which can have the effect of underestimating the full uncertainty and adding unnecessary constraints.

This paper presents an integrated system that can assist field development decisions. The complex relationships between the earth models, the development strategy and the economics are retained in the development decision process. A full-physics reservoir simulator is used to maintain high fidelity to the physics of both the subsurface and surface components. The interdependencies of underlying uncertainties can affect the choices to be made. The system described can be implemented for project decisions at any stage within an asset's life cycle.

In this paper, we illustrate the application of the system on a single, significant reservoir unit, taken through a development-planning exercise. The exercise includes coupled well and facility scenarios and evaluates economic outputs that are fully coupled with the flow simulation outputs. The reservoir is a faulted structure covering about 30 square miles and has around a 450 feet thick oil column. Uncertainties in the earth model were present in the static properties, faulting, and fluid-rock dynamic properties. Uncertainties included both distinct scenarios and continuous distributions. multiple choices around well placement, drainage strategies with and without injection, and scheduling are included. Ultimate recoveries, profiles, and ultimate economics for the range of possibilities are evaluated.
A Comparison of Techniques for Coupling Porous Flow and Geomechanics
Authors: Dean Rick H. , Gai Xiuli , Stone Charles M. , Minkoff Susan E.
Published: December 2007

This paper compares three techniques for coupling multiphase porous flow and geomechanics. Sample simulations are presented to highlight the similarities and differences in the techniques. One technique uses an explicit algorithm to couple porous flow and displacements where flow calculations are performed every time step and displacements are calculated only during selected time steps. A second technique uses an iteratively coupled algorithm where flow calculations and displacement calculations are performed sequentially for nonlinear iterations during time steps. The third technique uses a fully coupled approach where the program's linear solver must solve simultaneously for fluid flow variables and displacement variables. The techniques for coupling porous flow with displacements are described, and comparison problems are presented for single-phase and three-phase flow problems involving poroelastic deformations. All problems in this paper are described in detail so the results presented here may be used for comparison with other geomechanical/porous flow simulators.
Numerical Simulation with Input Consistency between Capillary Pressure and Relative Permeability
Authors: Li Kewen , Horne Roland N.
Published: December 2007

This study proposes a numerical simulation approach without direct specification of relative permeability functions. Using this approach, it is not necessary to impose relative permeability functions as input to the simulator in order to conduct the numerical simulations of two-phase fluid flow. Instead only capillary pressure data need to be imposed and the relative permeabilities can be calculated consistently using specific models. Example numerical simulations at both core and reservoir scales were conducted to test the technique without the direct input of relative permeability functions from experimental data. The results showed that the production performance calculating from the numerical simulations without the input of relative permeability functions was almost the same as the experimental data. Using the method proposed in this study, the effects of pore size distribution index and entry capillary pressure on oil recovery by gravity drainage were investigated at both core scale and reservoir scale. The technique may be especially suitable for reservoirs in which it is difficult to measure relative permeability curves. Such reservoirs include gas-condensate reservoirs, extremely low permeability reservoirs, and geothermal reservoirs. The proposed technique may also be useful to upscaling, numerical simulation while drilling, and other areas.
Classification of PDC bits According to their Steerability
Authors: Menand S. , Sellami H. , Simon C.
Published: December 2007

With the emergence of rotary steerable systems, the technical issue concerning the bit design for a specific directional application has reappeared. Today, a bit must be specifically designed for use with a particular directional system: rotary bottom hole assembly (BHA), steerable mud motor or rotary steerable system (RSS). The reason is that the bit must have the ability to respond properly and rapidly to a side force applied by the steering system in order to initiate a deviation as requested. To do so, the bit must have a predetermined steerability compatible with the directional system in order to provide the optimum dog leg potential.

The new generation of directional drilling systems differentiates "pointing the bit" from "pushing the bit". As a consequence, the bit directional response is a key factor that operators and directional drillers need to know to make the good adaptation between the bit and the BHA. However at the moment, there is no standard method that can propose a way to classify bits according to their steerability and walking tendency.

Based on a comprehensive analysis of the directional behavior of polycrystalline diamond compact (PDC) bits (numerical simulation, pilot and field tests), a simple methodology has been developed in order to define and evaluate the steerability and the walking tendency of PDC bits. This methodology is used to classify the PDC bits defined with their IADC bit profile codes.

As the PDC bit steerability is mainly a function of the bit profile, the gage cutters and the gage pad, some design recommendations are given concerning these three parts. For each IADC bit profile code, the bit steerability and the walking tendency is estimated through some formulas linking only the heights and lengths of the cutting profile. Some guidelines are also given about the gage pad length and gage cutters characteristics in order to achieve improved steerability.

This simple method based on geometrical criteria enables to estimate quickly not only the PDC bit steerability, but also the maximum dog leg potential achievable by the PDC bit, when coupled with the steering system.