bluuebunny/crossref_metadata_2025 huggingface dataset:
Selecting the Appropriate Rodless PC Lift System for a Highly Deviated Wellbore
Authors: Chachula R. C. , Mann J. S.
Published: December 2007

The process of developing various versions of rodless progressing cavity (PC) lift systems has been a major area for technological research and development work at PanCanadian Petroleum Ltd. Inherent production problems associated with highly deviated wellbores experiencing solids, varying aromatics and emulsions is consistently burdening the oil industry, especially as lifting and well intervention costs rise in environmentally sensitive areas. Through a collaborative venture with REDA, new and innovative systems have been developed and implemented to combat and overcome these operational problems. The recent developments of rodless PC systems have provided operators with an alternative approach to producing reservoirs from a conventional perspective.

Field results from medium crude oil reservoirs located below Lake Newell in southeastern Alberta, Canada suggest that pump performance and annular drawdown is mainly impacted by wellbore configuration, high solution GOR's and reservoir fluid rheology mechanisms. Conventional electric submergible pumps (ESP) and gas lift have been the artificial lift systems of choice to produce the highly deviated wellbores contacting the reservoirs. However, due to the apparent producing inefficiencies and costly workovers, alternate innovative lift systems to optimize operations were necessary. This prompted the need to develop systems to reduce downhole operating expenditures while achieving pumped-off capabilities.

This paper describes the evolution of bottom motor driven PC units, the selection process utilized in determining the final prototype system deployed and the results of the field trial. Modifications made to the equipment design and techniques to optimize pumping operations is discussed. It is hoped that the conclusions derived will be of benefit to other projects contemplating alternate system designs from the traditional approach.
A Solution to Instability Problems in Continuous Gas-Lift Wells Offshore Lake Maracaibo
Authors: Faustinelli Juan , Bermúdez Gastón , Cuauro Antonio
Published: December 2007

Unstable flow condition is a limitation for production optimization in continuous gas-lift wells due to casing and tubing heading. The instability could be caused due to insufficient gas injection volume, incorrect port diameter size, and variation of gas-lift injection rate due to subcritical flow condition at the point of operation. The traditional square-edge orifice valve is a cylindrical channel used to transport the gas. To reach critical flow condition, the downstream pressure has to be 50% to 40% the upstream pressure, and cannot be used to eliminate instability due to the excessive pressure differential required to achieve this flow regime. Therefore, a new valve was developed, which has the advantage to reach sonic flow velocity when pressure differential is only 10%, due to its converging diverging flow geometry. Comparing the dynamic flow performance of both square-edge and Nova valve, the Nova is independent of the downstream pressure and ideal as means of eliminating upstream instability.

Around 4200 wells currently operates under continuous gas-lift in Lake Maracaibo and 5% to 10% of these operates at unstable flow conditions due to subsonic flow at the injection point. For this reason PDVSA E&P decided to carry out field tests using a new gas-lift stabilization valve called Nova or nozzle-Venturi valve in wells with emulsion problems, high water content or low differential pressure across the operating valve which causes casing and tubing heading. There were installed 7 Nova valves in wells with crude oil gravity ranging from 14° API to 30° API, producing from 300 blpd to 2000 blpd, gas injection volumes of 500 Mscfd to 2000 Mscfd, and as deep as 12000 feet.

The well test results indicate that this new technology could stabilize the gas injection volume eliminating the casing heading and minimizing fluctuations of the tubing pressures. The potential application of this new valve in Lake Maracaibo oscillates between 300 to 400 wells. It is the scope of this work to present the selection criteria used to choose the well candidates, the results and experience gained during the field tests.
Probe Testing of Gas Lift Valves for Effective Performance Prediction and Better Gas Lift Design
Authors: Adiyodi K. S. , Kumar R. Sujith , Singh Rajiv
Published: December 2007

Optimum production from a gas lift well mainly depends on proper injection gas quantity, injection pressure and depth of injection. The quality of down hole gas lift valves plays a crucial role in achieving maximum efficiency of a gas lift system and un interrupted oil and gas production . This study carried out by probe testing and dynamic testing enable us to analyse the characteristics of the Bellows, termed as the heart of a gaslift valve, to predict various flow regimes, to design a gaslift system more accurately and proper monitoring of gaslift operation. The paper deals with Experimental Lab study and detailed analysis of approximately 200 probe tests and dynamic tests carried out on GLVs of different manufacturers.
Run Life Enlargement Methodology for Ball-and-Seat Check Valves Used in Artificial Lift Pumping Units
Authors: Zarea S. , Rojas-Solorzano L. , Kabboul F.
Published: December 2007

Experiments are performed to evaluate the leakage vs. pressure drop, wear and fluid properties, in ball-and-seat valves used in pumping units for artificial oil production. The test facility is constructed to evaluate the operation of several valve sizes, using water, oil and air, subjected to pressure drops up to 5000 psig. Results demonstrated that the currently accepted API vacuum test might be too severe and that more realistic tests may lead to substantial savings in valve replacements. Experimental results in dimensional and dimensionless form are presented, using a new similitude criterion.
Time-Critical Decision Making Using PC-Based Reservoir Simulation
Authors: Hazlett W. G. , Buchwalter J. L. , Calvert R. E. , Campbell T. M. , Molohon R. A.
Published: December 2007

Reservoir simulation has typically been applied to only the larger and more complicated reservoirs. The cost of performing such studies in a Unix/Workstation environment is high and most fields are not analyzed using reservoir simulation. High-power inexpensive PCs, and software with a powerful, user-friendly interface that does not require a simulation expert has changed the economics of performing such studies to such an extent that engineers and geologists are now using PC-based reservoir simulation to evaluate exploration plays on a real-time basis. This paper documents the process and results of a study that involved mapping, gridding, geostatistics and reservoir simulation of an exploration prospect while the drilling rig was on-site. The paper demonstrates the feasibility of using PC-based reservoir simulation as a routine part of reservoir management, beginning with the exploration well.
Lagomar's Integrated Field Laboratory for Intensive Evaluation of Technologies
Authors: de Carvajal G. , Velasquez A. , Graterol J. , Ramirez F. , Medina M. , Guimerans R.
Published: December 2007

PDVSA's light oilfields in Lake Maracaibo have been under exploitation for more than four decades. To date, the expected recovery factor is only 29% of the OOIP. As these resources approach maturity, it has been realized that improving recovery will demand the earliest use of many technologies, proven and new, in an integrated manner and tailored to solve specific regional problems. The Integrated Field Laboratory (IFL) philosophy is one of PDVSA's main technology strategies designed to accomplish these goals. Three Field Laboratories are being developed in the Maracaibo Lake Basin: one for heavy oils and two for light oils: shallow and deep reservoirs.

The VLA-6/9/21 area in Lagomar Field was selected to evaluate technologies with potential application to highly depleted, medium to light oil reservoirs, which are either under or have favorable conditions for waterflooding and at depths bellow 10000 feet. Venezuela has over 30000 MMSTB of oil currently in place in reservoirs with similar conditions. This huge volume of oil provides the incentive to conduct the work described in this paper.

The engineering management approach for technology evaluation being used is comprised of: 1)Advanced reservoir characterization, simulation and visualization, 2)Drainage strategies, including displacement processes and well architectures, 3)Well construction at minimum time, damage and cost, 4)Technologies to improve injectivity/productivity, 5)Advanced monitoring technologies aiming to intelligent reservoirs, 6)Technologies for handling produced and injected fluids and 7)Techniques to evaluate and quantify risk.

Multidiscisplinary multiparticipant virtual work teams have been structured in order to execute this project. These teams are being integrated with specialists from different disciplines within PDVSA, such as: Technology Department, Exploitation Units and Research Institute (Intevep), national and international universities, service companies, national and international consultants, etc.

This paper describes the main aspects of the design of Lagomar's Field Laboratory, the results obtained during the first year of operations, and the future plans. Some of the technologies currently under evaluation are: 1)High resolution reservoir characterization, simulation and visualization, 2)Well to well seismic, 3)Fluids for at balance drilling, 4)Foam cements, 5)Multiwell injectors, 6)Commingle production, 7)Massive fracturing and 8)Down-hole sensors.
Successful Pilot of Thermosyphon Process Heater Reduces GHG Emissions and Operating Costs
Authors: Arnold W. A. , Neulander J. I.
Published: December 2007

PanCanadian originally pursued thermosyphon technology to lower operating costs. However, it is now apparent that a more significant benefit is reduction of greenhouse gas (GHG) emissions. Other benefits include loss management, increased safety, improved operability and maintenance cost reduction.

A prototype Thermflo™ thermosyphon process heater was developed by Hudson Products Corporation (HPC) as a joint effort with PanCanadian Petroleum Ltd. The unit was installed in a 320 m3 atmospheric heavy oil tank in northeastern Alberta in November '97. Performance testing was carried out over the next several months and evaluated using API Standards & Recommended Practices.

The testing was carried out in two phases. In phase one, we compared the performance of the thermosyphon to a naturally drafted venturi style nozzle burner in a firetube located in an adjacent tank. Both units were fired using sales utility gas. Increased combustion efficiency and improved heat transfer reduced fuel gas consumption by 33% and cut GHG emissions by 40%. In phase two of the testing, the prototype successfully burned solution gas normally vented to atmosphere. This translates to an annual operating cost saving of about $40,000 and GHG emission reduction of about 10,000 tonnes per year.
Frac and Pack Completion Strategy in Duri Steam Flood (DSF) Field PT Caltex Pacific Indonesia
Authors: Satyagraha Mathias T. , Aimar Amritzar
Published: December 2007

Frac and Pack was introduced to Duri Steam Flood (DSF) in 1996 and has become the preferred completion technique. Frac and Pack combines the stimulation advantages of hydraulic fracturing with the sand control benefits of Gravel Packing.

Frac and Pack treatment was first used in Area 4 Rindu Vertical Expansion (RVE) Project. These wells were recompleted with a Frac and Pack completion into a shallower producing zone (Rindu Sand). Now Frac and Pack completion is used in almost all new and recompletion wells in DSF.

Frac and Pack treatment combines fracturing and gravel packing into one step with a liner in place. The Tip Screen Out (TSO) design technique is used to ensure that proper fracture width and proppant concentration are adequate to effectively connect the reservoir to the wellbore. The Frac and Pack job is finished with an annular sand pack between the wire wrapped screen and the cased hole.

This paper will share success story, best practices, lessons learned, and techniques in Frac and Pack completion. Opportunities for job cost reductions will also be shared. In addition, a comparison of Frac and Pack and Gravel Packs will be discussed.

In summary, Frac and Pack completion has proven to be very effective in DSF and can be used in other fields to increase well productivity and sand control performance.

History

Fracturing in DSF first began in the Rindu Pilot Project. The pilot test on fracturing technology was successfully performed on four cased hole wells in the Rindu Pilot area during December 1995 and January 1996. For the first time a screenless completion was used to complete the Rindu formation in DSF. This completion consisted of a tip screen out (TSO) fracture, using Curable Resin Coated (CRC) sand. This treatment was performed without gravel packed screen in the well.

A study of TSO's in A4-RVE found that a lot of wells experienced sanding problems. There may be multiple reasons for the failure of the CRC and the TSO Frac to control sanding. For instance, not all perforations received CRC sand during placement, steam from surface did not reach and cure CRC in the entire section, and non-CRC sand had already bridged over some of the perforations before or during treatment1.

From the result above, CPI tried Frac and Pack (FP) completion. FP was first tried in Area 4-RVE Project. These wells were recompleted with FP completion into a shallower producing zone (Rindu Sand). Now, FP completion applies in almost all new and recompletion wells and has become the preferred completion method in sand control environments in DSF.
Application of Honeycomb Welded Structures to Petroleum Engineering Facilities
Authors: Okuto K. , Fujita K.
Published: December 2007

Honeycomb welded structures were first introduced to the 5th INALCO ‘92 and further developed into some application stages since that time. A successful stage is marked by the use of honeycomb panels to the coach shell of a hundred sixty Shinkansen bullet train bodies which are running in commercial operation begun at the end of 1998. Another application is found in roofing members of several architectural building structures in Japan. Manufacturing procedures of honeycomb and sandwiched panels by welding are also developed and introduced ever since.

Because aluminum or steel panels thus manufactured are weldable, the structures fabricated and erected are termed as "Honeycomb Welded Structures". Further studies have been carried out, finding some more applications in the petroleum related fields of industry. An example in the paper is light-in-weight but strong and rigid enough roof for oil storage tanks. Further uses are considered to the various structural members for top-side facilities in production-, accommodation- and drilling-offshore platforms, and even in drilling rigs.

The paper specifically emphasizes the superior characteristics of honeycomb welded structures, inevitably related to the rigidity, strength, fabrication and construction capabilities. Design procedures are reviewed briefly, and a conceptual design for oil tank roof is discussed in detail. In addition, fabrication and erection examples are illustrated, for the sake of better comprehension of honeycomb welded structures.
First Diverless Subsea Wireline Well Intervention Performed in Offshore Vietnam offers Low-Cost Solution for Light Well Workovers: Case Histories and Future Trends
Authors: Larimore David , Ashwell Charles , Abidin Abdul Halim Zainal
Published: December 2007

Subsea completions have been on the rise in recent years due to the economics, extreme environments, the use of infrastructures (subsea tiebacks), and migration to water depths in excess of 1300-feet. In this paper, subsea slickline operations are performed on three cluster wells situated beneath the operator's semi-submersible floating production unit in Vietnam's offshore Dai Hung field. The services were needed for reservoir management, including installation and retrieval of memory gauges, performance of logging surveys, and to manipulate sliding sleeves that had been installed with the ultimate purpose of optimizing hydrocarbon recovery. A subsea wireline unit (capable of deploying slickline and electric line) was chosen to provide the services. This unit was selected because of its cost efficiency and capability to perform a fishing job without impacting platform space and weight restrictions on the floating production unit as would have been imposed by use of a drilling riser. This paper will provide the case history of these services, which were unique in that these were the first diverless subsea slickline jobs performed solely with remote-operated vehicle (ROV) support for manipulation or assistance. Slickline provided an effective solution for the operator's service requirement within the specified criteria. Because of the versatility of newly developed advanced systems, slickline equipment was able to meet the restrictions of weight and size on platforms to provide a more efficient alternative for services that traditionally require rig mobilization.

As a result of the success of this operation, the operator is planning other subsea slickline services that will be performed without a drilling or jack-up rig.

With the present economic climate of the oil-and-gas industry, the significant costs normally associated with heavy workover and drilling facilities have strengthened the need to find other ways to enhance cost efficiency in subsea workover scenarios. To support this trend, innovative methods that have expanded the scope of operations that can be performed on subsea wells without a drilling rig have now been introduced. As an example, plug and abandonment operations can be performed with subsea wireline intervention units and other coiled tubing and wireline intervention techniques rather than with a tensioned riser from an anchored drilling vessel or a jack-up rig. With the new methods, the deployment system for wireline and coiled tubing does not require special system modification—any standard wireline or coiled tubing unit can be used. These techniques will be discussed more fully in the paper.
Nuclear Magnetic Resonance and Carbon/Oxygen Logging Improve Determination of Residual Oil Saturation: A Case Study from the Minas Field
Authors: Eyvazzadeh Ramsin Y. , Nguyen Chuong , Fox Phil , Peornomo Bambang
Published: December 2007

The effect of pore-fluid diffusion on nuclear magnetic resonance (NMR) measurements is now being used to quantitatively determine oil saturation in subsurface formations. This new NMR application is helping improve interpretation models for carbon/oxygen (C/O) measurements.

This paper discusses the petrophysical advantage of combining the very different NMR and C/O measurements to better define near-borehole oil saturation. The Minas Field in central Sumatra has been logged extensively with C/O and NMR tools and provides a case study that exemplifies the new logging and data-interpretation methodology.
Coiled-Tubing Stretch and Stuck-Point Calculations
Authors: Newman K.R.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE/ICoTA Coiled Tubing Roundtable held in Houston, Texas, 25–26 May 1999.
Coiled Tubing Milling and Temporary Plug and Abandonment Operations
Authors: Sørgård Eirik , Østvik Egil , Grønnerød Njål , Svanes Grete , Villar John , Salvesen Tom , Tjåland Lars
Published: December 2007

In order to establish barriers to enable a safe removal of a sub sea BOP, two temporary cement plugs had to be placed in the 10¾″ casing using 2″ coiled tubing (CT).

The operation was performed from a floating drilling/production semi submersible rig in 360 m water depth connected to the well by a marine riser.

A 23/8″ hole was milled through a BOP testing tool assembly (BTT), which had become stuck below the BOP due to a malfunction of a BOP ram, while containing well control throughout the operation.

A novel OBM formulation design was utilized in order to clean up the settled solids in the OBM in the well through the 23/8″ milled hole.

A novel cement packer was run down to 2000 m through the 23/8″ milled hole and set in the 10¾″ casing, allowing a successful cement plug to be placed in a 46 degree inclination at extremely low pump rate utilizing coiled tubing. A similar cement plug was set and tested at 900 m using the same method.

The whole operation was completed successfully considering that a lot of uncharted coiled tubing technology was utilized.
Coiled Tubing String Longitudinal Properties
Authors: McCoy Terry , Avakov Vladimir , Rosine Randy , Martin John
Published: December 2007

This paper discusses test results of material properties along the length of a coiled tubing (CT) string that was manufactured in 1997. The 1.50-in. OD, 0.102-in. WT, 9,052-ft CT sting was made from 80-ksi yield strength material. The new string was manufactured with conventional procedures and was cut into 362 25-ft segments. The segments were properly numbered, protected against corrosion, and stacked. Among them, 128 segments were chosen for testing.

Samples from the test segments were prepared for fatigue testing and tensile testing. Fatigue testing was performed with a bending machine having a 48-in. bending arch and 4,000-psi internal pressure. Tensile testing was performed with full-body specimens to determine yield strength, ultimate tensile strength, modulus of elasticity, elongation, and reduction of area.

A total of 252 samples were tested. Test data are statistically analyzed, and their distributions along the length of length of the CT string are plotted. The results are compared with correspondent specifications and standards.
Application of C.T.D. Offshore, Indonesia Phase One Pilot Project
Authors: Kirk Andrew , Sembiring Taufiq
Published: December 2007

The trend of increasing jack up drilling rig rates in 1996 and the fact that Atlantic Richfield Indonesia Incorporated (A.R.I.I.) has many wells on tripod platforms are the primary factors for ARII to find an alternative way to drill sidetrack wells on tripod platforms. One possible solution is Coil Tubing Drilling (CTD). This paper is a case study of Arco Indonesia's 1997-98 CTD pilot project describing the operation of CTD on these platforms. The focus of this paper will be on; rig up of surface equipment, operational overview and lessons learned for future wells using CTD on tripod platform wells.
Downhole Video Optimizes Scale-Removal Program
Authors: Tague J. R. , Hollman G. F. , Chaffin G.
Published: December 2007

In fields with potential for scale buildup, downhole video offers a unique and cost effective method for obtaining direct visual data of scale in the wellbore environment. In a recent study, Chevron successfully used downhole video logging to obtain actual images of scale deposits in producing wells. These images were used to design and optimize a scale removal program in the West Coalinga field of Central California.
Simulation of Early-Time Response of Single-Well Steam Assisted Gravity Drainage (SW-SAGD)
Authors: Elliott K. T. , Kovscek A. R.
Published: December 2007

Steam assisted gravity drainage (SAGD) is an effective method of producing heavy oil and bitumen. In a typical SAGD approach, steam is injected into a horizontal well located directly above a horizontal producer. A steam chamber grows around the injection well and helps displace heated oil toward the production well. Single-well (SW) SAGD attempts to create a similar process using only one horizontal well. This may include steam injection from the toe of the horizontal well with production at the heel. Obvious advantages of SW-SAGD include cost savings and utility in relatively thin reservoirs. However, the process is technically challenging.

To improve early-time response of SW-SAGD, it is necessary to heat the near-wellbore area to reduce oil viscosity and allow gravity drainage to take place. Since project economics are sensitive to early production response, we are interested in optimizing the start-up procedure.

An investigation of early-time processes to improve reservoir heating will be discussed. We performed a numerical simulation study of combinations of cyclic steam injection and steam circulation prior to SAGD in an effort to better understand and improve early-time response. Results from this study, including cumulative recoveries, temperature distributions, and production rates display variances within the methods. It is found that cycling steaming of the reservoir prior to SAGD offers the most favorable option for heating the near-wellbore area and creating conditions that will improve initial SAGD response.
Flexible, Real-Time Tip-Screenout Fracturing Techniques as Applied in California and Alaska
Authors: Upchurch E. R.
Published: December 2007

This paper discusses the application of two variations on a flexible tip screenout (TSO) technique that allows for realtime changes of fracture treatments to compensate for uncertainty in fluid leakoff and fracture geometry. The basic premise for each technique is the same; that is, change frac job size as necessary during the job to attain a TSO using realtime data. The techniques differ, however, because of physical system constraints, which result in different types of data being available to make real-time decisions. In the West Sak Field of Alaska, real-time bottom-hole pressure is available for decision making purposes (a best-case scenario). In the East Wilmington Field of California, real-time bottom-hole pressure is not available; thus, the flexible TSO technique is implemented differently to yield the best possible flexibility under these less-than-optimal data conditions.
Evaluating High-Angle Wells With Advanced Production-Logging Technology, North Slope Alaska
Authors: Schnorr DeWayne R. , Hupp Doug
Published: December 2007

High-angle wells with longer and longer departures are being drilled at an ever-increasing pace on the North Slope of Alaska. This type well is used to penetrate new oil reservoirs and increase oil recovery in older fields. These older oil fields are under waterflood and gas injection to maintain reservoir pressure, and the wells are producing oil with high water cuts and high gas-to-oil ratios. This is a very complex environment to evaluate with production logs.

To assist in these complex interpretations, data from a new production logging tool string are being used to determine the production profile when a high-angle well is producing oil with high water cut and high gas-to-oil ratios. This compact tool string directly measures water holdup distribution around the wellbore, phase velocity data and provides X-Y caliper information. All measurements can be acquired as close as 16 in. (40 cm) to the bottom of the tool. Sensors to acquire data on pressure, temperature, inclination, gamma ray and casing collar locator are included in the tool string. The measurements can be made in either telemetry or memory modes. The memory mode eliminates the need for electric line when logging horizontal wells, or wells that have high surface flowing pressures.

Sensors for sigma/porosity and carbon oxygen measurements can be combined with this logging string (when run on wireline), so that the production profile and the reservoir behind the casing can be evaluated on a single trip. The combined data from the production profile and the formation are then used to determine how to produce the well and manage the reservoir for maximum oil production and recovery.

Production profiles from three wells are used to demonstrate the value of these direct measurements and how they were used in remedial work to increase oil production and reduce or eliminate unwanted gas and water production.
Scale Management Through Laboratory Analysis and Wellbore Monitoring Surveys
Authors: Carbone C. Leandro , Fleming Niall , Spark Iain , Patey Ian
Published: December 2007

This paper highlights the role which laboratory analyses together with in-situ monitoring surveys have helped in the scale management programme for the Dunbar Field, a very water sensitive reservoir situated in the South-Central part of the Shetland Basin, block 3/14. The major formation damage mechanism in Dunbar is that on production, the mixing of separate formation and injection brines drops out a sulphate scale within the near wellbore and wellbore itself. In order to solve this problem, TOTAL in conjunction with COREX (UK) Ltd., Aberdeen designed a laboratory programme to best mimic field scale treatments under reservoir conditions. Two separate water based scale inhibitors were assessed to evaluate their compatibility within the reservoir and identify any damaging mechanisms, which could result from their squeeze application. The interpretation of the permeability data obtained from the coreflood tests was aided by X.R.D. (x-ray diffraction), dry and cryogenic S.E.M. (scanning electron microscopy) and thin section analyses to determine the nature of the formation damage mechanism(s).

The coreflood test results suggest that the major control on permeability impairment was the retention of a compound believed to be derived from the scale inhibitor which occurred as a thin film, hemispherical globules with a moderate wetting preference and/or irregular shaped globules with a high wetting preference. Retention of this substance reduced pore volume and narrowed pore throats, hence reducing permeability.

In conjunction with the laboratory testing wellbore monitoring surveys were undertaken. Production and caliper logging tools were run to gather wellbore data and to give an indication of any decrease in wellbore diameter with time through sulphate scale drop out. Wellhead pressure and topside sampling of the connate/injection water mixture was monitored to determine if any scale precipitation was occurring and of what type.

The evaluation of the laboratory data plus the information obtained from wellbore monitoring surveys were complemented by the more global recommendations issued by a task-force which includes, in particular, TOTAL's partner Elf Exploration UK PLC. It is on this basis that Total based its decision on the most suitable downhole scale management programme for the Dunbar Field.
Alternative Method for Stimulating Open Hole Horizontal Wellbores
Authors: Purvis D. L. , Smith D. D. , Walton D. L.
Published: December 2007

Drilling and completing horizontal wells has become an accepted method to connect natural fracture systems and increase the effective drainage radius. In the Madison formation of the Williston Basin, common practice is to complete the horizontal laterals as open hole. Production is through natural fracture swarms combined with tight matrix permeability. Without stimulation, production has often been disappointing from these wells. During the drilling of the horizontal interval, cuttings are ground into a fine powder. These fines combined with polishing and other horizontal drilling damage mechanisms plug the near wellbore porosity. The fines flow into and effectively plug the natural fracture systems. In order to maximize production rates, some treatment is necessary to remove or stimulate past this damage. This can best be achieved by creating multiple radial fractures or alternately connecting with and widening the natural fracture systems. Several methods have been utilized in the past to achieve this with varying degrees of success.

This paper examines a different approach to this problem. With this process, it is possible to create multiple radial fractures or connect to natural fracture systems in the most promising sections of the open hole. This is done with jointed tubing placement and the use of an oil soluble diverting medium to block acid from reaching previously treated intervals as well as other sections of the open hole. The use of divertor to channel acid combined with conventional tubing diameters allows achievement of significantly higher bottom hole stimulation pressures. The application of this process is presented along with case histories identifying the challenges and the results achieved to date.
Assessment of Foamed – Cement Slurries Using Conventional Cement Evaluation Logs and Improved Interpretation Methods
Authors: Frisch Gary J. , Graham William L. , Griffith James
Published: December 2007

Methods to evaluate conventional cements with logging data may not yield valid results in foamed cements. Logging tools commonly used in cement evaluation are the traditional cement bond log (CBL) tools and the modern ultrasonic scanning tools. CBL tools provide waveform images and acoustic amplitudes that together help describe cement-to-pipe and cement-to-formation bonding. Ultrasonic scanning tools contribute circumferential images and detailed information regarding the cement-to-pipe bond. The major problem in evaluating foamed cements is that their impedance values can be below that of annular fluids, such as mud or water. Thus, a standard interpretation of ultrasonic images and data in foamed cements may provide an incorrect diagnosis of the cement bond and could lead to unnecessary remedial cementing activities.

A new interpretation method expands and improves on previously published methods to effectively evaluate foamed cements with the common cement-evaluation tools. This method uses ultrasonic scanning data to provide detailed information regarding the cement-to-pipe bond and allows foamed cement to be distinguished from mud or spacer fluid behind casing. Cement-slurry weight and composition do not affect this technique. The technique does not require additional logging tools or passes and thus does not introduce additional logging or rig expenses.

Examples are presented showing that the new method is valid and is effective in both time and cost. These examples will illustrate several new ultrasonic cement-bond curves that were developed as a result of the new method and that, when used in conjunction with CBL amplitude data, improve foamed-cement evaluation. In the examples, the interpretation is focused to answer the basic question, "Should remedial cementing be performed, or should the well be perforated for production?"
Acoustic Method for Determining the Static Gel Strength of Slurries
Authors: Moon Jeff , Wang Steven
Published: December 2007

Complex chemical reactions are occurring within a cement matrix as it becomes a solid. During the initial phase of the cement hydration, the cement exhibits polymer characteristics that exhibit a shear yield point that has been described as "static gel strength" (SGS). Due to this behavior, the cement slurry develops SGS after it has been pumped downhole. The start of gel strength development signals the point at which the cement slurry begins to change from a true hydraulic fluid that transmits full hydrostatic pressure to a solid material that has measurable compressive strength. The cement gel strength is important for two reasons:

The static gel strength development determines the shut down safety factor on the job. If the cement slurry is stopped prior to placement, then the static gel strength allows the calculation of the pressure required to restart circulation. The static gel strength affects the hydrostatic pressure distribution and the flow of gas or water into the cement filled annulus, known as fluid or gas migration.

This paper describes the discovery that as some slurries develop static gel strength, the attenuation of a high frequency acoustic signal transmitted through the slurry decreases. This change in amplitude correlates with the actual static gel strength of the slurry.

An acoustic method and system for determining the static gel strength of a cement slurry sample has been developed that provides nearly continuous, accurate, non-mechanical measurements of the static gel strength of cement slurry samples. The measurements are made at wellbore temperatures and pressures up to 400°F, 20000 psig.
Vacuum Jacketed Tubing: Past, Present, and Future
Authors: Bunton Mark A.
Published: December 2007

Vacuum jacketed tubing has been used for many years in steam flood EOR applications and protection of permafrost. The product more recently has been applied to production tubing for hydrate and paraffin prevention. The paper will discuss case histories and economics of the various past uses of vacuum jacketed pipe along with potential new applications such as vacuum jacketed pipelines. We believe that the superior insulating ability of vacuum jacketed tubing could be an integral part of the rejuvenation of Alaska's oil production in both steam flood and production tubing applications.
Use of Pressure Activated Sealants to Cure Sources of Casing Pressure
Authors: Rusch David W. , Ellis Barry C.
Published: December 2007

Pressure leaks in a wellhead or in downhole tubulars or equipment can lead to inoperable subsurface safety valves, casing pressure, environmental pollution, loss of production and, in extreme cases, blowouts. As such, it is essential to the safe and environmentally sound operation of a well that the sources of the pressure leaks be identified and cured. Use of a new and unique pressure activated sealant technology allows utilization of a method of repairing wellhead and downhole leaks in-situ without employing any mechanical downhole operations. Only at the point of differential pressure, through the leak site, will the sealant reaction occur and create a bond across the leak. Use of the pressure activated sealant technology obviates the need to employ expensive and risky rig or wireline operations to cure downhole leaks.
Outstanding Economic Advantages Based on New Straight-Hole Drilling Device Proven in Various Oilfield Locations
Authors: Calderoni A. , Savini A. , Treviranus J. , Oppelt J.
Published: December 2007

Tremendous savings in drilling investment have been made possible through application of a new drilling concept and directional system. The Straighthole Drilling Device (SDD) has migrated from an experimental system into a mature tool, which is now used to a major economic advantage in different places of the world. At first sight this device's advantage seems to be mainly the ability to drill a borehole into the ground with a vertical trajectory. However soon after the earliest applications in a commercial environment it became obvious, that this new kind of directional tool allows in fact to revolutionize the way of drilling.

Much beyond the mere benefits of a straight and geometrically exact borehole shape, SDD technology actually offers the opportunity to completely re-configure the well trajectory. The final result of this are considerable savings in time and investment to arrive to well production. According to the current knowledge base, the SDD is also be extremely helpful in locations, were the formation has a natural tendency to build up hole inclination.

SDD has been used in several different hole sizes, there providing a higher penetration rate, and a very smooth and precise hole trajectory. This in turn allows to drill wells in a cluster approach, and to apply the lean casing concept. Also curved sections in the lower part of the hole do considerably gain with respect to lower friction in the drill string to borehole wall contact. Finally, a considerable positive environmental impact is associated with this technique, in terms of reduction of waste disposals at about 30% in volume, compared to a standard well profile.

Basically the SDD comprises a positive displacement motor section, a control sub having electronic and hydraulic means, and a bearing assembly equipped with selectively expandable stabilizer pads. The system does autonomously drill a straight, vertical hole, where no surface human interaction is required. Whenever the directional sensors detect any small deviation from the vertical, one or more of the ribs will be activated in a closed loop circuit. Standard mud pulse transmission allows to monitor the down hole operation.

SDD was originally developed for the German Scientific Ultra-Deep Well (KTB), but later on turned out to be of considerable advantage for major oil and gas fields in Italy. SDD has so far seen it's most utilization in South of Italy, which is the center of Italy's onshore oil and gas exploration. Meanwhile additional application has occurred in other places around the Mediterranean Sea. A considerable interest has recently developed within several drilling areas in South America.
Wet Crude Transport through a Complex Hilly Terrain Pipeline Network
Authors: Alvarez Carlos J. , Al-Awwami Mofeed H.
Published: December 2007

This paper discusses the results of steady-state and transient flow simulators utilized in the design, operation, and troubleshooting of a complex multiphase pipeline network in a Saudi Arabian oilfield. The oilfield pipelines pass across a hilly terrain with sand dunes rising up to 200 meters, transporting wet crude from wells located on sabkhas (flat terrain) to three Gas Oil Separation Plants (GOSP). State-of-the-art transient multiphase flow model performance was also evaluated using pipeline slug flow tests measurements.

The results of various steady-state algorithms used for pressure drop and free-flow calculations in the Field's pipelines were found inaccurate and inconsistent. A comparison of these calculations and Field data demonstrates that they should not be used for predicting pressure drop, sizing multiphase pipelines, or designing production facilities over hilly terrain. Transient multiphase models can more accurately predict pipeline pressure drop, and optimize pipeline size. A transient multiphase model was used for simulating trunkline valves for slug flow control. Based on simulation results, plug valves were installed near trunkline outlets. The valves were found to be useful in mitigating effects of slugs into the receiving separators, thus eliminating the need for installing costly slug-catchers. Different free-flow alternatives, and crude pumping for transferring wet crude from satellite GOSP's to the Central Processing Facility (CPF) were examined. Crude pumping was found the most suitable and economical option due to large pipeline pressure drop resulting from slugs.

Transient multiphase flow continues to be highly complex. Its effects are hard to predict accurately. Pipeline pressure drop results from simulations using the latest commercially available flow models were about 20-30 % lower than Field measured values.
Two-Phase Well Test Analysis of Gas Condensate Reservoirs
Authors: Xu Shaosong , Lee W. John
Published: December 2007

This paper proposes a new method to interpret transient pressure data from gas condensate reservoirs. Our method models two-phase gas-condensate flow in the reservoir using traditonal solutions to flow equations for single-phase, slightly compressible liquid flow by employing a pseudopressure function and fluid properties derived from conventional laboratory experiments.

The method is especially useful for well test analysis when reservoir pressure is near or below the dewpoint, where existing methods fail. Their assumption of steady-state flow yields a relation between reservoir condensate saturation and pressure that is not valid at these low pressures.

In this paper, we show that an accurate relation between reservoir condensate saturation and pressure can be computed from the assumption of a three-zone radial model, in which steady-state fluid flow is assumed in the first zone, the condensate is immobile in the second zone, and only the gas phase exists in the third zone. (Whether the third zone exists or not is determined by reservoir average pressure.) The second zone becomes increasingly important at lower pressures.

The essential problem in multiphase well test analysis is to establish the correct relationship between saturation and pressure needed to calculate pseudopressure. We verified our calculated relationship between reservoir condensate oil saturation and pressure by comparing our analytical results to results generated by compositional simulation. The comparison also showed that our proposed relationship between reservoir condensate saturation and pressure leads to accurate test interpretations and is much more satisfactory than previous methods.

Once the correct relation between reservoir condensate oil saturation and pressure is obtained, our method can compute and correlate pseudopressure with either producing or shut-in time. Sensitivity studies for various reservoir and fluid conditions support our conclusions under a wide variety of conditions.

Our test interpretation method provides good estimates of reservoir permeability and initial reservoir pressure. Mechanical skin is usually overestimated, but only modestly (typically about one unit of skin).

Our method requires lab constant volume depletion (CVD) data, gas and condensate oil relative permeability, and producing GOR in addition to transient pressure data. The effects of non-Darcy flow, wellbore storage, and capillary number-dependent relative permeability are not considered. The production wells are fully penetrated.
Analysis and Interpretation of Well Test Performance at Arun Field, Indonesia
Authors: Marhaendrajana T. , Kaczorowski N. J. , Blasingame T. A.
Published: December 2007

This paper presents a comprehensive field case history of the analysis and interpretation of all of the available well test data from the giant Arun Gas Field (Sumatra, Indonesia). Arun Field has estimated recoverable reserves on the order of 18-20 TCF and has 110 wells—78 producers, 11 injectors, 4 observation wells, and 17 abandoned. Approximately 100 well tests have been performed, and the analysis and interpretation of these data suggests strong existence of condensate accumulation near the wellbore as well as a "regional pressure decline" effect caused by competing production wells.

We demonstrate and discuss the analysis/interpretation techniques for wells that exhibit condensate banking and non-Darcy flow. We found that the 2-zone radial composite reservoir model is effective for diagnosing the effects of condensate banking at Arun Field.

We also demonstrate the development and application of a new solution for the analysis and interpretation for wells that exhibit "well interference" effects. Our new solution treats the "interference effect" as a regional pressure decline and this proposed solution accurately represents the well interference effects observed in many of the well tests obtained at Arun Field. Furthermore, this solution is shown to provide a much better interpretation of well test data from a multiwell reservoir system than the existing approaches–i.e., assumption of no-flow or constant pressure boundaries, data truncation, etc.