bluuebunny/crossref_metadata_2025 huggingface dataset:
Evolutionary Well-Construction Method That Challenges Convention
Authors: Howlett P. D. , Wardley M. T. , Black C. , Reed D. , Begg G.
Published: December 2007

This paper will describe the development, prototype testing, full well system test and the first field trial of an evolutionary slender well construction system. The system is a method of constructing oil and gas wells from close-clearance flush-jointed cemented liners from top to bottom to form the entire well.

Significant technical hurdles were overcome in the development of a system that is safe and practical to deploy whilst at the same time allowing drilling and completions engineers to plan the wells using accepted oil and gas well engineering methods. The paper will describe the technical hurdles to overcome to enable this method of well construction to become accepted.

This evolutionary method of constructing oil and gas wells has the potential to compete favorably with conventional techniques and other new technology methods already being deployed and could be used in a wide variety of well types.

In its full well construction format of four or more close-clearance liners, the cost of constructing the well can be reduced significantly, perhaps by more than 50%, whilst at the same time enhancing safety and reducing environmental impact. In its partial format of one to three close-clearance liners during a sidetrack or well extension, the available flow area across the zone of interest can be increased by 100% as a result of an increased tubular size deployed at total depth compared with convention. Figure 1 shows a comparison of the system to conventional techniques for full wells and Figure 2 shows the flow area increase of the system in its partial format.
Risk Analysis for Water Injection in a Petroleum Reservoir Considering Geomechanical Aspects
Authors: Rodrigues L. G. , Cunha L. B. , Chalaturnyk R. , Cunha J. C.
Published: December 2007

Economic and risk analysis are important tasks in a petroleum engineering study. This work considers the analysis of the results obtained from a real Brazilian offshore field simulation study in which the decision making process for field development is discussed considering geomechanical aspects. The focus is on the evaluation of uncertainties of geomechanical parameters that may influence the response of a petroleum reservoir submitted to seawater injection for secondary recovery. A decision tree has been built and solved using utility theory and the expected monetary value (EMV) concept. A sensibility analysis for different discount rates and oil prices has been also performed.

First, this work identifies if the reservoir is a candidate for a deeper analysis using a matrix approach consisting of important geomechanical parameters. Second, lab stress information is used and the results obtained compared with the traditional reservoir simulation, which considers compressibility invariant with time. Third, a decision tree is constructed and solved. Based on the assumptions chosen for these analyses, it is concluded that coupled reservoir-geomechanics simulations should be applied in order to more precisely forecast reservoir performance.
Verification and Proper Use of Water/Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs
Authors: Balogun A. , Kazemi H. , Ozkan E. , Al-Kobaisi M. , Ramirez B.
Published: December 2007

Accurate calculation of multi-phase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a very crucial issue. In this paper, we will present the viability of the use of a simple transfer function to accurately account for fluid exchange resulting from capillary and gravity forces between fracture and matrix in dual-porosity and dual-permeability numerical models. With this approach, fracture and matrix flow calculations can be decoupled and solved sequentially, improving the speed and ease of computation. In fact, the transfer function equations can be easily used to calculate the expected oil recovery from a matrix block of any dimension without the use of a simulator or oil recovery correlations.

The study was accomplished by conducting fine-grid simulation of a typical matrix block and comparing the results with those obtained with the use of a simple transfer function for a water-oil system. This study was similar to a previous study (Alkandari, 2002) we had conducted for a gas-oil system.

The transfer functions of this paper are specifically for the sugar-cube idealization of a matrix block, which can be extended to simulation of a match-stick idealization in reservoir modeling. The basic data required are: matrix capillary pressure curves, densities of the flowing fluids, and matrix block dimensions.
UniTong Combined Tong for Drilling Operations
Authors: Halse Helge-Ruben
Published: December 2007

This paper gives a short introduction to the first field tested, multi power tong capable of handling drill pipe, tubing and casing using the same tong and crew. The tong is called UniTong and lets one operator handle all tubulars from 2 7/8" to 22" casing, without the need for dedicated casing or tubing tongs.

What makes this tong unique is its capability to be parked concentrically on the well centre. Drilling, tripping and casing operations can be performed through the centre of the UniTong. No movement to and from the rotary table is required, as with traditional equipment, and associated crane operations for equipment movement to and from the rig floor are greatly reduced. The UniTong is completely remotely operated, eliminating manual handling by rig crews; operations are conducted from the safety of the driller's cabin. This has a significant impact on well site safety.

Incorporated as an integrated part of the tool is a mudbucket, dope applicator and thread wash system. These applications are also remote operated and can be automatically sequenced.

To switch between drillpipe, tubing and casing modes only the clamp houses have to be replaced, in three intervals 2 7/8"-9 ½", 9 ½"-16" and 18"-22".

The closed concentric design of the tong makes it very robust and durable. All clamp forces are absorbed into the drive ring and the metal fatigue normally experienced with traditional casing/ tubing and iron roughneck tongs is eliminated.

The tong can exert extremely high torques of up to 150 000 ft/lbs (210 000Nm). Existing casing tongs lack this high torque capacity and as a result have difficulty handling dopeless connections, crucial to the zero-pollution goal set by a number of oil companies.

In 2005, the UniTong design was awarded the prestigious "Woelfels Best Mechanical Engineering Achivement Award" in Houston, Texas.
Simultaneous Estimation of Aquifer Parameters and Original Hydrocarbons In Place from Production Data using Numerical Inversion of Laplace Transform
Authors: El-Khatib Noaman
Published: December 2007

A new method is presented for the simultaneous estimation of original hydrocarbons in place OHIP and aquifer parameters for a circular aquifer surrounding a hydrocarbon reservoir. Water influx data are represented by the van-Everdingen and Hurst (VEH) unsteady state solution. In addition to the initial oil and/or gas in place, the aquifer parameters are also estimated. These parameters include the water influx constant B, the relative aquifer size ReD, and the time adjustment factor c which transforms real time t into dimensionless time tD.. The parameters B and c can be used to estimate the storativity h ϕCt and the transmissibility kh/μ of the aquifer.

The method of least squares is applied to the material balance equation to estimate the parameters resulting in a non-linear regression problem. Because the solution in Laplace space is simpler than the solution in the real time domain, numerical inversion of Laplace transform was used to obtain the partial derivatives of the VEH solution with respect to aquifer parameters needed for least squares method. Nonlinear regression analysis using numerical inversion of Laplace transform is applied. The Levenberg method was used for parameter estimation to guarantee convergence when the initial guess is not close enough to the correct solution..

The model is linear with respect to original hydrocarbons in place N, Gi, and the water influx constant B, but is nonlinear with respect the dimensionless aquifer size ReD and time adjustment factor c which transforms real time t into dimensionless time tD.. Assuming the values for c and ReD enables the calculation of N, Gi, and B and hence the estimation of the sum of squares of the residuals .Maps of the sum of squares of the residuals are generated and displayed to show regions of maxima and minima in the aquifer parameters space. Maps explain the non-uniqueness of the solution usually encountered in nonlinear least squares. The knowledge of the approximate values of some of the aquifer parameters from geological and engineering data will help choosing the proper initial guess to achieve convergence to the correct solution
Step Changes Needed To Modernize T&D Software
Authors: Mason Colin J. , Chen David C. -K.
Published: December 2007

Torque and drag (T&D) modeling is regarded as an invaluable process to assist in well planning and to predict and prevent drilling problems. Although T&D software has existed for over 20 years, some confusion still exists over the validity of the models used to characterize drilling and completion operations. This paper provides an assessment of current limitations of the various T&D models (soft-string and stiff-string) and appraises their validity. Field data from various operations is used to illustrate certain limitations. The paper defines future requirements for what is considered to be the next generation of T&D models. Probably the most important technical requirement is a more realistic stiff-string model to correctly account for the impact of tubular stiffness, hole clearance and tortuosity effects.
Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Orito Formation
Authors: Rozo Rafael , Paez Javier , Mendoza Alberto , Milne Arthur , Soler Diego
Published: December 2007

The Orito field in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir, is the Caballos Formation, a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft that has produced (30 to 45 °API crude) for over 35 years, with production peaking at 66,000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the past, attempts were made to hydraulically fracture one or more of the sands, using a variety of different (water- and oil-based) fluids. However, many of the wells indicated positive skin factors following the fracture treatments, irrespective of the fluid system used. In at least one case, a well stopped producing after being treated.

A core study revealed that despite the relatively low clay content in the formation the critical velocity was less than one cc/min. Moreover, the retained matrix permeability after performing a static leakoff test (500-psi differential for 30 minutes) was less than 5%, regardless of the fluid used. From this testing it was concluded that the reduction in the permeability was due to the mechanical plugging of the kaolinite or disrupted mica in the pore throats. This reduction in the matrix permeability creating a very high fracture face skin that would account for the higher skin factors following fracture treatments.

To eliminate the fracture face skin created during the fracture treatment a new treatment incorporating a pre-pad of acid viscosified with a solids free visco-elastic surfactant was developed. By incorporating this stage into the fracturing treatments, the retained matrix permeability was increased to +/- 30%, resulting in a negligible fracture face skin. The productivity of fracturing treatments performed using this technique resulted in negative skin factors and production ratios that exceeded expectations.
Application of Novel Technology Improves Drilling Performance in Multilateral Field Development Offshore West India—Reducing Risk and Increasing Production
Authors: Jaggi Anil , Gera Sanjeev , Upadhyay Sunil , Gupta Manoj , Thorat Ashok , Ruszka Jon , Tatake Sandeep
Published: December 2007

The Panna Field is located offshore West India and is operated by BG Exploration and Production India Limited. The reservoir is a tight limestone which is drained using multilateral wells. There are significant drilling challenges. Firstly, the well trajectories are complex to reach the reservoir and the laterals are three dimensional profiles requiring precise steering control to maintain position in the productive zones. Secondly, total fluid losses to the fractured limestone are frequently encountered. Thirdly, high levels of vibration and high drilling torque threaten the integrity of the drillstring and ultimately limit the reach to which the lateral sections can extend. A rotary closed loop drilling system had been use to successfully drill the wells, but the desire to improve gross drilling performance, reduce the risk to drillstring and extend the reach of the laterals prompted introduction of a new drilling system which was being tested in the North Sea. This new system integrates a high performance drilling motor with high speed rotary closed loop system to improving overall drilling performance in challenging areas, reduce stress on the drillstring and enable wells to extend past prior reach limits.

On the first well; rate of penetration increased by 46%, the distance drilled per BHA increased by over 300% and the longest ever lateral in the field was successfully drilled. Based on the performance noted on the initial well, the new system was used on a further six Panna tri-laterals – completing the drilling campaign ahead of schedule.

This paper discusses challenges drilling to and through the Panna field reservoir with the reasoning behind mobilization of the new drilling system to the area at an early phase of its introduction. The overall results of drilling the tri-laterals are then presented.
Managing Production in Maturing Assets: Increasing Intervention Success by Combining Production Logging with Nodal Analysis
Authors: North R. , Lenn C. P. , Stowe I.
Published: December 2007

A new processing workflow has been engineered to combine reservoir deliverability, defined by production logging (PL) measurements, with nodal analysis evaluation. This allows the effects of various completion modifications to be quantitatively modeled, predicting the resulting changes in well production prior to intervention.

A graphical computer interface is used to implement the workflow and facilitate comparisons of the effect on production of multiple completion/recompletion scenarios, using "drag and drop" icons for placing simulated plugs, patches, perforations, etc. on the base profile. Beginning with the flow profile and formation pressure, the process defines zonal reservoir parameters in terms of the productivity index, water cut, and gas/oil ratio. These data are passed transparently to a nodal analysis package that automatically creates a model to match the measured rates and pressures as closely as possible to allow production computations.

The process is designed to significantly decrease workover decision time and risk. This technique provides opportunities to compare and recommend formation evaluations, profile modifications, various artificial lift options, and stimulation activities to maximize production. The modified completion is then passed to the nodal analysis engine and a new predicted production profile is computed and displayed. Outputs include graphic and ASCII format log data, ASCII format tables, and data files, which can be used for further studies.

In this paper, the use of the workflow is demonstrated by one example and two case studies, including a selective inflow performance analysis of a gas well and a successful water shutoff operation in an oil well.

PL answers provide an opportunity to evaluate the downhole flow performance of multizone completions. Nodal analysis techniques provide a method to model the effects of the fluid properties and completion configuration as the fluids are produced to the surface. Combining PL answers seamlessly with nodal analysis provides unique insight into the reservoir completion performance and production improvement potential.
Validation of Splitting the Hydrocarbon Plus Fraction: First Step in Tuning Equation of State
Authors: Al-Meshari Ali A. , McCain William D.
Published: December 2007

Volumetric data and phase behavior of volatile oils and gas condensates are very sensitive to the fluid composition and the properties of the plus fraction. Since the plus fraction of a reservoir fluid has some uncertainty in its measured molecular weight, the equation of state, EOS, is generally not predictive unless its parameters are tuned to match the experimental data. Characterization of the plus fraction, which is important in tuning the EOS, consists of splitting the plus fraction to single carbon number groups, assigning critical pressure, critical temperature and acentric factors to each single carbon number group, SCN, and then grouping single carbon number groups to multiple carbon number groups, MCN.

Direct measurement of the critical pressure, critical temperature and acentric factor of the plus fraction is not practical. Several authors have shown that erroneous predictions and calculations can result if the plus fraction is used directly as one component in EOS calculations and that use of the extended composition of the measured plus fraction will give more accurate PVT predictions for crude oil and gas-condensate mixtures.

To tune EOS three main steps should be followed: (1) Extend the measured composition into SCN, assign critical properties and acentric factor for each SCN, and match saturation pressure using the extended composition (2) Group SCN into pseudo-components, group the properties of the pseudo-components, and rematch the saturation pressure using the grouped composition and (3) Match PVT properties.

The objective of this study is to find an accurate method for splitting the hydrocarbon plus fraction to single carbon number groups and then validate the proposed method by using experimental extended fluid composition of different reservoir fluids. The proposed method was compared to other splitting methods published in the literature.
New Offshore Rigless Intervention System
Authors: Harris David , Adams Paul G.
Published: December 2007

Application

This paper will discuss the successful use of a new "Rigless Intervention System" [ RIS] as an alternative to the use of a Drilling Rig or Workover Rig for the Abandonment of Conductors, Pre Installation of Conductors, Sidetrack and Whipstock operations. The RIS system has also been used on a Tension Leg Platform for the pulling of Production Risers because deck load limitations ruled out the use of a workover rig.

With rigs becoming increasingly scarce, operators are being forced to delay abandonment and drilling plans for weeks, even months. For those operators with the foresight to anticipate this shortage, they have found an environmentally friendly hydraulic rigless intervention system as a means of extracting and pre-installing conductors without a rig.

The system has been performing for a number of operators in the Gulf of Mexico and internationally. The system reduces the amount of time and expense associated with installing conductors by pre-installing them prior to the arrival of the drilling rig, using the system to handle the joints and then for them to be driven with hydraulic hammers. On the conductor extraction side, the system speeds the process of abandoning multiple wells on fixed platforms.[See Fig. 1]
Case Study in Water Shutoff Fluid Placement Using Straddled Through-Tubing Inflatable-Packers Technique
Authors: Kelkouli Redha , Razouqi Maen , Al-Shaheen Saeed , Al-Khamees Abdul Rasool , Dashti Abdulaziz Abdulla
Published: December 2007

Most of the wells in Sabriya Field (Northern Kuwait) produce from reservoirs, where multiple layers are opened to production. Problems related to non-desired water production are drastically affecting the oil production, and have been an ongoing concern. The exclusion of this water represents a challenging task by itself especially in case of multiple zones interval simultaneously producing, and where completion of the wells restricts considerably the convoyed down-hole tools configuration

This paper covers water shut off case history of an oil producer that has shown according to the production data an increasing water production figures. The nature of water problem and the fact that the targeted section is located in-between multiple oil producer zones revealed the necessity of a complex thru tubing zonal isolation solution before performing the water shut-off treatment. Temporary coiled tubing conveyed straddle system was created using two thru tubing inflatable packers, isolating the top and bottom perforated zones in order to provide both proper zonal isolation and accurate treatment placement. The post water shut off treatment showed up to 70% water flow reduction from the targeted layer has been achieved.
Flow Rate Effect on Two-Phase Relative Permeability In Iranian Carbonate Rocks
Authors: Alizadeh A. H. , Keshavarz A. R. , Haghighi M.
Published: December 2007

The effect of flow rate on relative permeability curves has been investigated in very tight Iranian carbonate rocks. Core samples were prepared from outcrop of Asmari formation. Asmari formation represents huge oil carbonate reservoirs in Iran. This formation belongs to Oligocene-Miocene period and is mainly limestone. The dynamic displacement experiments were performed at three different flow rates. In all experiments, we injected both water to displace oil and oil to displace water and relative permeability curves were generated with the Jones and Roszelle method for both water-flooding and oil-flooding experiments.

We found a critical rate in which we could not obtain any relative permeability curves above this rate. This critical rate represents the limit of injectivity capacity of each core sample. We observed that in the water-flooding process, water relative permeability curves and its end points were not affected by flow rate. However, it was detected that the oil relative permeability decreases at lower flow rates. This variation vanishes at the central saturation points. During oil-flooding experiments, we also observed the same no rate effect in water relative permeability curve but in the oil relative permeability curves, although it was seen the flow rate effect, it was not found any meaningful trend in the curves and its end-point saturations.

We found hysteresis effect in both water and oil relative permeability curves. At higher flow rates, the effect of this phenomenon increases in water relative permeability curves while the hysteresis effect decreases in the oil relative permeability curves.
Fractured Wellbore Stress Analysis: Sealing Cracks To Strengthen a Wellbore
Authors: Wang Hong (Max) , Towler Brian F. , Soliman Mohamed
Published: December 2007

Wellbore pressure containment, the maximum pressure that a wellbore can withstand before whole drilling mud begins to leak off into formations, defines the upper bound of the mud weight window. Drilling costs are heavily associated with this mud weight window in terms of expensive casing programs or nonproductive time because of narrow mud weight windows.

Although various methods have been developed using different materials for curing mud losses, the performance has been poor as a result of the lack of engineering design for the materials and placement techniques. The commonly used "trial and error" approach reveals inadequate understanding of the challenge, although a number of advances have been accomplished in recent years.

In this paper, results are reported from a fundamental study aimed at revealing the basic physics that control the success of treatments strengthening wellbores or widening the mud weight window. It first focuses on reviewing and identifying factors that can reduce the upper bound of this mud weight window, followed by analysis of wellbore strengthening that can increase this upper bound of mud weight window, especially by sealing hydraulically conductive cracks at the wellbore.
Calculation of Flowing Bottomhole Pressure Constraint Based on Bubblepoint-Pressure-vs.-Depth Relationship
Authors: Obeida T. A. , Mosallam Y. H. , Al Mehari Y. S.
Published: December 2007

Thick reservoirs usually have variations of PVT properties such as bubble point pressure and dissolved gas oil ratio with depth. A considerable effort usually spent to describe such properties to be used in dynamic models either in Black Oil or compositional simulators. However, during predictions many dynamic models set the BHP constraint as a constant value for all producers in the entire reservoir regardless of perforations depth. Usually this constant value is close to the average bubble point pressure or a little higher to ensure single phase (oil) production and not considering changing of bubble point pressure with depth.

The above procedure introduces uncertainty regarding well potential, which involves a risk of not presenting accurate well performance in the simulator and would impact oil production and recovery forecasts.

The proposed method was developed to calculate following BHP constraint based on bubble point pressure versus depth relationship for each grid cell in the dynamic model, thus creating 4D-array (I, J, K, BHP constraint) for the entire reservoir.

The proposed method is fully automated and tested to assign BHP constrains in schedule section of huge dynamic model (2.6 million cells) with 600+ wells.

Two prediction cases were tested (each case run twice, one run with constant BHP constraint for all the produces and the other one using variable BHP constraint recommended by the proposed method) to evaluate the impact of BHP constraint on production and oil recovery forecasts.

The results of these two runs showed a considerable difference in length of oil production plateau and oil recovery forecast, but negligible differences in gas oil ratio.

The proposed method could be used for any dynamic model with vertical and/or horizontal variation of bubble point pressure to calculate an optimum BHP and thus WHP to maximize production rate without the risk of introducing gas phase at reservoir conditions.
Field-Test Results of an Acoustic MWD System
Authors: Neff J. M. , Camwell P. L.
Published: December 2007

Acoustic telemetry (AT) MWD systems are finally coming of age as a commercially viable alternative to mud pulse and electro-magnetic propagation systems. Building upon our theoretical and experimental knowledge and understanding of communicating through the steel walls of drill pipe we have developed a practical, high data rate, acoustic telemetry system for use in drilling assemblies. We utilize one of the passbands that allow acoustic signals to propagate through the periodic structure of typical drill pipe.

In this paper we describe the field test program used to evaluate our through-bore AT system performance and demonstrate its practical and commercial applications. The program was limited to shallow, vertical and directional land wells (<2,500m) drilled with jointed pipe using both kelly and top drive systems. The AT tool was placed in a number of different locations in both rotary and steerable BHAs. A variety of operational modes and configurations were tested. The system performance was evaluated for various carrier frequencies and baud rates (5, 10 and 20bps) while signal, battery, decoding and reliability data were recorded and evaluated. The AT system performance was found to be acceptable for commercial applications. Significant time savings and improved drilling efficiency were demonstrated. Test results, including the present AT system limitations, are presented. As far as the authors are aware, the AT system has achieved the highest wireless data rates in a drilling environment compared to mud pulse and EM telemetry.

The system as it exists today is suitable for use as a rig-operated, automated, survey-on-connection tool in shallow wells. Several technical innovations have enabled the successful development of our system including advanced digital signal processing techniques and novel signal-to-noise enhancement techniques, as confirmed by field trials.
Effective Matrix Acidizing in Carbonate Reservoir – Does Perforating Matter?
Authors: Bartko Kirk M. , Chang Frank F. , Behrmann Larry A. , Walton Ian C.
Published: December 2007

It is well known that in cased-hole completions productivity is enhanced by maximizing shaped charge penetration and shot density while minimizing perforation damage. However, in tight carbonate reservoirs, creating deep and clean perforations may still not be enough to generate the desired productivity. Therefore the wells are often stimulated by a matrix acidizing treatment after the perforating. A prevalent mind set in the industry is that acid dissolves the perforation debris and creates wormholes that bypass the perforating and other near wellbore damage, therefore perforating design is not important as long as it serves the purpose of puncturing through the casing.

This paper presents recent research that looks into the impact of perforating on matrix acid stimulation. Large scaled single-shot perforating tests were conducted using real shaped charges to perforate carbonate core samples under downhole conditions. Acid was then injected into the perforations to create wormholes. The acid injectivity was measured, and the wormhole patterns through perforations generated by different perforating designs were compared using CT scans. It was found that clean perforations promote not only higher acid injectivity, but also initiate straighter and more dominant wormholes, while the un-removed perforation debris causes the wormhole to start with a more deviated pattern.

In the paper the required perforating design to create clean perforations is discussed for low permeability gas reservoirs. The effect of perforating with acid in the wellbore as the completion fluid is also examined. The implications and suggestions to safely apply the technique of perforating with acid are discussed.
Constant-Pressure Analysis of Infinite-Conductivity Fractured Gas Wells Influenced by Non-Darcy Flow Effects
Authors: Nashawi Ibrahim Sami
Published: December 2007

Non-Darcy flow effects have long been recognized to have serious adverse impact on the performance of high-flow rate gas wells. These effects may mask the presence of fractures around the wellbore of naturally fractured reservoirs and may render the effective fracture conductivity and fracture half-length of hydraulically fractured wells much less than the designed parameters. Proper diagnosis of the post-fracture well test and good estimation of the fracture parameters are crucial for proper MHF treatment assessment and production forecast.

Even though the effects of non-Darcy flow have been identified in the field and properly acknowledged in the well testing literature, little has been done to improve the well test analysis results. This paper presents for the first time a semi-analytical equation that incorporates the effects of non-Darcy flow in the fracture. The proposed equation describes the flow of real gas under constant bottomhole-pressure condition which has the advantage of reducing the well test duration and minimizing the wellbore storage effects. A detailed investigation of the various parameters influencing the flow behavior of real gas in the fracture nearby the wellbore is also illustrated.
Design, Development, and Qualification of a Threaded and Coupled Connector for a Sour-Service-Compatible Completion and Workover Riser
Authors: Craig Gordon , Bailey Greg , Ethridge Roger , Byrne Wes
Published: December 2007

Offshore reserves are being exploited at ever increasing water depths. These fields require high pressure and thermal capabilities to develop and produce them. H2S is often a concern, if not initially, then after water injection wells are brought on line. The weight penalty of tubulars can be managed by utilizing elevated hardness, NACE MR-0175 compliant alloys such as API 5CT Grade T-95.

Riser connections often constist of forged and machined elements welded to pipe. This approach has been used for many riser types including production, completion/work-over and drilling. Although the connectors can be robust and fatigue resistant, welding restricts the use of T-95 and similar grades due the lack of weld procedures which maintain sulfide stress cracking resistance as determined by Method A.

Premium threaded and coupled type connections are widely used for high performance casing and other downhole applications. Historically, fatigue resistance is not required. Grant Prideco has initiated efforts to optimize the fatigue resistance of this type of connection. Threaded and coupled connections are presently in use in the Gulf of Mexico and other offshore locations as top tensioned production risers.

Their use as tool strings such as work-over risers and landing strings has been restricted by perceived sensitivity to galling and make/break capacity. Threaded and coupled connections used for casing and tubing applications are not typically optimized for the level of galling resistance required for tool strings. As detailed in this report, this type of connection can be enhanced to achieve the required make-break durability.

A large operator requested the development of a threaded and coupled connection for 7-5/8" x 71.60# (1.00" wall) T-95 riser pipe for use as a tool string capable for use in the installation, work-over, and flow test operation for subsea production systems. The string would be deployed in both open water and through the drilling riser, in 6,000 ft. of water from a moored, floating facility.

A design strategy was employed for this project which would optimize success while reducing development time and cost. Existing threaded and coupled designs were optimized for the application, which included the use as a tool string. An aggressive time-line was required, and met, for the design, development and qualification of this riser.

This paper describes the design, development and qualification process, offering insights into strategies and tactics employed to meet the functional design challenges, as well as the schedule requirements of this project.
The Evolution of Advanced Well Completions To Enhance Well Productivity and Recovery in Saudi Aramco's Offshore Fields
Authors: Sunbul A. H. , Hembling D. , Al Qudaihy D. S. , Al Harbi N. A. , Salerno G.
Published: December 2007

The Offshore sandstone reservoirs in Saudi Arabia are characterized by high production potential due to the nature of the reservoir, consisting of clean coarse sand with active bottom water aquifer and in some areas, a gas cap as drive mechanisms.

In recent years, horizontal wells have replaced conventional wells due to their improved deliverability and recovery efficiency. The initial completion method selected by Saudi Aramco for the horizontal wells was mainly cased hole cemented with selective perforation strategy. This completion method was troubled by non-uniform flow profiles, which drastically shortened the well production life reducing the benefit associated with the planned horizontal wells.

This paper will describe the concept of an innovative openhole completion strategy that has increased well productivity and recovery compared to past horizontal completion methods. The paper will show the evolution starting with the use of openhole completions completed with passive Inflow Control Devices (ICD) allowing production optimization by delivering uniform inflow along the entire horizontal section. The paper continues to discuss the benefits associated with the integration of the passive inflow control system with artificial lift (In situ gas lift and Electrical Submersible Pump (ESP) and finally reveals plans to couple passive inflow control with active intelligent well completion technology for multilateral wells. Actual field data will be presented to validate findings and support conclusions.
Constant-Pressure Analysis of Oil Wells Intercepted by Infinite-Conductivity Hydraulic Fracture Using Rate and Rate-Derivative Functions
Authors: Malallah Adel , Nashawi Ibrahim Sami , Algharaib Meshal
Published: December 2007

Wellbore storage effect can highly degrade conventional pressure buildup and drawdown tests data disturbing the formation characterization of the wellbore surrounding area. Constant bottomhole pressure tests will eliminate this pitfall and provide good reservoir describtion.

This paper applies direct synthesis technique for infinite conductivity fractured wells producing at constant bottomhole pressure from finite reservoirs. Without resolving to type-curve matching or regression procedures, this technique analyzes the log-log plot of the reciprocal rate and reciporocal rate derivative data to determine the fracture and reservovir parameters. These plots reveal the presence of straight lines corresponding to linear and pseuso-radial flow regimes; while the the boundary flow effect is detected by an exponential behavior. A 0.65 slope straight line describing the transition period between the pseudo-radial and the boundary effect flow regimes in rectangular systems is also presented. The distinct features of the straight lines' slopes and intersection points are used to calculate various reservoir and fracture parameters such as fracture half-length, reservoir permeability, skin factor, drainage area and shape factor. Equations corresponding to the points of intersections are very useful to verify the accuracy of the results obtained from the slopes of the different flow regimes.

A systematic step-by-step procedure illustrating the methodology of the proposed technique for the analysis of linear, pseudo-radial, pseudosteady state flow regimes is described. Detailed examples using different simulated cases are presented to show the applicability of the proposed method.
Step Change in Remote Exploration
Authors: Shafer Randall Scott
Published: December 2007

Remote Arctic onshore exploration can be very costly, frequently exceeding the cost of a deepwater Gulf of Mexico well. This paper reviews the reasons for these high costs and a possible combination of new proven technologies and rig designs to significantly reduce these costs

Logistics, mobilization, demobilization and a limited drilling season are factors that combine to cause high costs. Operation time requirements and the short drilling season normally results in a rig drilling one well per season.

A significant reduction in exploration final hole size is the primary driver in reducing costs as this leads to a major reduction in rig size. Downsizing does not limit well evaluation due to recent developments in downsizing evaluation equipment. The majority of the required information can be obtained with this finder well or "scratch and sniff' approach.

This downsizing allows the use of an innovative rig design; hybrid coil tubing drilling unit; that has significantly reduced mobilization and demobilization times. The reduction in drilling and mobilization/demobilization time can result in one rig drilling multiple wells in the drilling season.

Combining new technologies, such as casing drilling and coil tubing drilling, reduces drilling time and allows the hybrid coil tubing rig to drill deeper. Casing drilling and coil tubing drilling are areas where ConocoPhillips is an industry leader.

A significant reduction in exploration cost is predicted, estimated at 50%.
Revealing the Real Picture Behind Safety Performance Statistics
Authors: Cram Robert S.
Published: December 2007

Traditional safety performance continues to be centred round measurements such as Lost Time Injury Frequency Rate (LTIFR) or Total Recordable Injury Rate (TRIR). In themselves, these metrics do not provide an adequate picture of actual safety performance.

Naturally, all organisations want to see a continuous improvement in their safety performance as reflected by a steady decrease in LTIFR and / or TRIR. The downside to such measurements is that they do not take into account normal fluctuations that are inevitable, due to the randomness of accidents and incidents.

All too often, a period of good safety performance is followed by a period of poor performance. It is not uncommon for this to promote an instinctive reaction by management to investigate what has gone wrong and make changes to correct the problem. Unfortunately, in many cases, a clear picture of what is happening is not available, resulting in uninformed decisions being taken.

It is easy to paint a false picture with numbers. This paper describes the issues surrounding misinterpretation of safety performance figures and proposes an alternative metric which can be used not only to measure improving (or otherwise) safety performance but will also accommodate random short term fluctuations in safety figures.
A New Delay Additive for Hydraulic Fracturing Fluids
Authors: Putzig D. E. , St. Clair J. D.
Published: December 2007

A new delay agent has been developed which has hybrid functionality versus previously-reported materials. It delays viscosity development in fracturing fluids based on guar derivatives crosslinked with a variety of common zirconate and titanate crosslinkers under a wide range of pH. The viscosity development can be optimized by adjusting the concentrations of polymer, crosslinker, and delay additive to give the desired profile for a given hydraulic fracturing application.
Parametric Investigations of a Modified SWAG Injection Technique
Authors: Algharaib Meshal , Gharbi Ridha , Malallah Adel , Al-Ghanim Wafaa
Published: December 2007

The natural energy of hydrocarbon reservoirs gets depleted as production continues. The restoration of reservoir energy involves the injection of gas and/or water to support reservoir pressure and to provide a sweeping mechanism. Due to the unfavorable gas-oil mobility ratio, gas injection alone often results in early breakthrough and thus poor sweep efficiency. Water and gas might be injected alternatively, as in water-alternating-gas (WAG) processes, or together, as in simultaneous water-alternating-gas (SWAG) processes, to improve the sweep efficiency. These processes improve the sweep efficiency by stabilizing the displacement front.

In this paper, we study a new design of SWAG process, in which water is injected at the top of the reservoir and gas is injected at the bottom. The difference in water and gas densities provides a sweeping mechanism in which water tends to sweep hydrocarbons downward and the gas tend to sweep the hydrocarbons upward. It is expected that the two displacement mechanisms will work together to enhance the overall sweep efficiency and thus the oil recovery. In this paper, the drive mechanisms responsible for oil production under this injection technique are analyzed. The effects of several design parameters on these drive mechanisms are investigated for both homogeneous and heterogeneous reservoirs. Such parameters include; mobility ratio between water and oil phases, viscosity ratio between gas and oil phases, lateral aspect ratio, location of the water and the gas injection wells, and injection rates of water and gas.
The Wafra First Eocene Reservoir Partitioned Neutral Zone (PNZ), Saudi Arabia and Kuwait: Geology, Stratigraphy, and Static Modeling
Authors: Meddaugh W. Scott , Dull Dennis , Garber Raymond A. , Griest Stewart , Barge David
Published: December 2007

The First Eocene reservoir at Wafra Field was discovered in 1954 and has produced about 290 million barrels of 17-19° API, high sulfur oil. The dolomite reservoir is Eocene/Paleocene age. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well log and core plug porosity values over 45% are common and measured permeability values range up to 5000 md. The First Eocene reservoir has an average depth of about 1300 feet and a gross thickness of about 750 feet. The OOIP is about 9 billion barrels.

The reservoir largely consists of dolomitized packstones and grainstones deposited under arid to semi-arid conditions on a shallow, very gently dipping, low to moderate energy inner shelf or ramp setting in a gently dipping, restricted ramp environment. The presence of some interbedded evaporites suggests restriction was occasionally sufficient for the development of hyper-saline lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds and exposure surfaces that are correlative with gamma ray highs that can be easily correlated across the 20 km length of the field and are the basis for the current sequence stratigraphic interpretation.

Several full field and small, highly detailed reservoir models have been generated using stochastic workflows to assist management of on-going primary development as well as two steamflood test/pilot projects. The reservoir models utilize the new stratigraphic framework and are constrained by over 285 wells with high quality porosity logs and six wells with high quality core descriptions and core plug data. Model properties were distributed by stratigraphic layer and constrained by layer-appropriate data (or transforms) and layer-appropriate semivariograms. The range parameter for the semivariograms models used in full field static models varied between 1100-2200 m with moderate anisotropy in the direction N120°E.
Performance Evaluation of Acid Treatments in Seawater Injectors with Reference to Two Clean-up Techniques
Authors: Beheiri F. I. , Nasr-El-Din H. A. , Rahman M. K. , Shedid S. A.
Published: December 2007

An appropriate post-stimulation clean-up process for matrix acidizing treatments in carbonate reservoirs is essential to ensure that the created wormholes are not damaged by precipitation of the reacted fluids. This paper presents a methodology to compare the performance of the clean-up injection displacement technique with that of the flowback technique. These two techniques were attempted in several seawater injectors in a Saudi Arabian oil field. Several variables that control the flow performance are normalized to accurately evaluate and compare the two post-stimulation clean-up techniques.

Based on a well defined criterion, the study analysed historical data from 72 treatments: 42 treatments employing the post-stimulation flowback technique and 30 treatments employing the injection displacement technique. A detailed statistical analysis using actual data from these wells was also carried out.

The results indicate that the flowback technique outperforms the injection displacement technique.