bluuebunny/crossref_metadata_2025 huggingface dataset:
Casing Running Tool
Authors: Kamphorst G H. , van Wechem G. L. , Boom W. , Böttger D. , Koch K.
Published: December 2007

During casing running, risks of accidents with the stabber, the stabbing board and around well centre are still existing. In order to reduce the risks of accidents and to streamline the process a new Casing Running Tool is developed.

The basic idea of this device is that the Top Drive is used as a torque wrench and that several functions are integrated. A flush mounted spider is used. Integrated in this device are fill up and circulating functions, the power tong function, the top stabbing function and the casing hoisting function. The risk for accidents will be significantly reduced. The driller's operation is simplified and the casing running time is reduced. The Casing Running Tool incorporates additional features, such as the possibility of pushing and rotating the casing string while circulating. The reduction of casing running time, personnel, and risk of accidents create value and HSE benefits.

A first prototype is being developed. Design constraints that can be recognised at this stage of the development of the tool are mainly related to mechanized connection making. Both a theoretical and experimental approach are taken in order to define the design constraints.

In the development of the Casing Running Tool a step by step approach is chosen. All subsystems are designed as add-on equipment.

The Casing Running Tool paves the way to a complete automation of the drilling process.
Formation Evaluation in Ultra deep Wells
Authors: Henkes Ian J. , Prater Terry E.
Published: December 2007

Deep-water oil and gas exploration in the Gulf of Mexico has recently been the focus of much attention owing to the untapped potential of such a vast area. Of particular interest is the Garden Banks area, where sedimentary structures have been mapped using surface and borehole seismic techniques to depths greater than 30,000 ft. Formation evaluation at depths approaching 30,000 ft has necessitated the development of new technologies in the areas of tool conveyance and high pressure/temperature limitations. These new technologies have been put to the test in the logging of the deepest well ever drilled in the Gulf of Mexico, Garden Banks 386 #1. This well, located in 2663 ft of water, was drilled to a depth of 27,864 ft.

The Operating Company worked closely with the Service Company to prepare for the logging operation months in advance. The resultant technology and equipment included: Array induction, sonic, and integrated lithology and porosity tools rated to 500 °F and 25,000 psi for wireline formation evaluation.Extra strength logging cables in excess of 36,000 ft for tool conveyance.Surface mounted Wireline Dual Drum Capstan for surface tension reduction.The TLC* (Tough Logging Conditions) drillpipe/wireline conveyance system used in conjunction with wireline fluid sampling tools to sample the formation fluids downhole.

Utilizing these technologies resulted in the successful evaluation of the well. These new techniques and equipment will ensure proper evaluation of the continually increasing number of ultra deep wells.
Pressure Investigation Accomplished With Hydraulic Snubbing and Pressure Control Concentric Tubular String
Authors: Goodman Charles E. , Baker Robert V. , Smith Mike , Denton Kelly R.
Published: December 2007

Re-entry of a temporarily abandoned offshore well offered a unique well control challenge. When the 7-in. liner and 6-in. open-hole section had been drilled, well control problems had left the liner cement bond with questionable integrity. The well was ultimately circulated with kill weight fluid and a 100-ft surface cement plug was installed in the 9 ⅝-in. casing. A temporary abandonment (TA) cap was placed in the 9 ⅝ in. and the 13 ⅜-in. mudline hanger equipment. The 30-in. conductor pipe was severed 9 ½ ft above the mud line.

Two years later, subsurface investigation indicated that bubbles were escaping from the wellbore. The danger was that reservoir pressure was migrating under the surface TA caps. The authors were members of the pressure control team called in to solve the problem.

In planning for re-entry, the team designed a means of pressure investigation that relied on hydraulic snubbing equipment and well control expertise. The 13 ⅜-in. casing, with a burst rating of 3,450 psi, was the limiting factor to pressure control in a situation where 7,500 psi surface pressure was possible. The plan included installing a platform over the well, using a jackup rig, tying back the 30-in. conductor, removing the vented 13 ⅜-in. TA cap, and tying it to the platform. The team designed an elaborate surface blowout preventer (BOP) stack that included dual 8-in. overboard diverters and a pressure-confining tubing string which latched mechanically to the 9 ⅝-in. TA cap. Because it would be necessary to vent or bleed the potential well pressure to zero or use other means to kill the well for conventional re-entry, the team also designed a pressure investigation tool. A 150 K series hydraulic snubbing unit with 1 ¼-in. CS Hydril tubing would convey the tool to depth, where it would check surface pressure under the 9 ⅝-in. TA cap.
Drilling Fluid Considerations for Gulf of Mexico Depth Record
Authors: Prater Terry , Gleason Dan , Henn William E.
Published: December 2007

A synthetic fluid (Linear Alpha Olefin/Ester 90/10 blend) with a S/W ratio of 70/30 was designed and used to successfully drill a slim hole in the Garden Banks area of The Gulf of Mexico. Several service companies contributed to the operator's success in setting Gulf of Mexico records for the deepest MD (27,864â€²), TVD (26,979â€²) and setting a production liner at a record depth of 26,750â€² MD (25,772â€² TVD). This paper details the challenges met and overcome from the drilling fluids perspective in achieving these GOM records.
Drill String Considerations for Gulf of Mexico'S Deepest Well (27,864')
Authors: Prater Terry E. , Everage S. DeWayne , Greenip John F. , Adams Burt A.
Published: December 2007

This paper chronicles the design analysis performed to drill the Gulf of Mexico's deepest well. With small diameter casing cemented in the hole, slim hole drilling plans for the record depth well were generated. The short fuse project required atypical slim hole drill string design to select a string with ample tension/torsion capacity, sufficient flow area for hole cleaning, and immediate availability. The final design was utilized in an "edge-of-envelope" environment with remarkable success. This paper discusses the factors involved in drill string selection and acceptance, actual field data, post well results, and future applications.
Pyro Technology for Cutting Drill Pipe and Bottomhole Assemblies
Authors: Cole James F.
Published: December 2007

In recent years, limited advances have been made in drill pipe recovery services technology. Depending on the size, weight per foot, and type of pipe stuck in the well, the options available to separate the pipe string, have remained the same for over a decade. These include:

String shot/back off Chemical Cutter Jet Cutter Metal Severing Tool

The most commonly used tool is the string shot/back off, which involves applying left hand torque to the pipe string at the neutral weight. The explosive produces and intense hammer blow and allows the joint to be unscrewed at the desired connection. The most difficult part of this procedure is determining the neutral weight at the depth of the back off attempt and the amount of torque required at that point.

The back-off is a preferred method because it leaves a clean top on the down hole fish. This saves time in the fishing operation, which is critical to a successful fishing job. However, as wells become more deviated or well conditions become more severe, the back-off method can become less effective.

This paper introduces new technology for disengaging pipe located above the point where the drill string assembly is stuck. The system uses a solid combustible mixture which produces sufficient heat to separate drill pipe, leaving a clean top on the remaining down hole fish. The sytstem is safe to store, transport and handle at temperatures up to 660°C. It's solid combustible mixture does not ignite due to pressure, shock or impact, under normal conditions.
The True Value Of Automated Rotary Directional Drilling Technology is Demonstrated on a Well Offshore Brunei
Authors: Ruszka Jon , Vos Anton , Otter Bert , Othman Osmera Bin Hj
Published: December 2007

The Iron Duke Field, offshore Brunei, Borneo is operated by the Brunei Shell Petroleum Company. Fourteen wells have been drilled in the Iron Duke area over the life of the field, with a high degree of local experience having been gained. One area of operations which has consistently been troublesome is that of performing controlled directional drilling. Following the recent introduction of Rotary Closed Loop System (RCLS) drilling technology, an in depth-study of offset well data was carried out to determine whether application of this technology was a solution to any of the common problems encountered. The results of the study showed that all of the identified problems could be eliminated through use of a Rotary Closed Loop Drilling System. A suitable well was identified as a trial for the system and tools were mobilised from Europe for use in the 8½" hole section. The results of the well clearly demonstrated many of the advantages in using this new technology, with the resultant hole section being of higher quality and delivered with a time saving of 55%.

This paper outlines the common problem areas identified from the offset data study. It shows how application of the new technology eliminated these problems and resulted in a step change in both drilling performance and wellbore quality.
A ‘Keep It Simple’ Approach for Managing Shale Instability
Authors: Tan C. P. , Chen X. , Willoughby D. R. , Choi S. K. , Wu B. , Rahman S. S. , Mody F. K.
Published: December 2007

An efficient ‘keep it simple’ approach to the management of wellbore instability in shales is presented. It takes into consideration the factors which determine whether conducting a stress-induced wellbore stability analysis would be sufficient or complex time-dependent drilling fluid-shale interaction and thermal stress mechanisms need to be taken into account in the development of a mud weight program.

A range of design and analysis tools required for wellbore stability analysis is described systematically. The tools include practical guideline charts for stability analysis, optimum wellbore profile and wellbore drillability, design charts of pore pressure change due to drilling fluid-shale interaction mechanisms, shale property database and correlations, and simple stress-induced and complex time-dependent wellbore stability analysis software.

The application of all the tools is demonstrated through three field case studies to develop strategies to control shale instability in wells drilled in the North West Shelf of Australia. The tools provide a practical means of optimising the approach in developing the solution, including drilling fluid design (weight, type and chemistry), to manage shale instability efficiently.
Conductor Sharing—A Viable Alternative to Multilaterals and Slot Recoveries
Authors: Dharaphop J. , Borisutsawat C. , Chaisangkha V. , Boyne K. , Thouvenin E.
Published: December 2007

Conductor sharing allows two or more wells to be drilled from a single drilling slot, expanding well capacity of a platform at minimal cost. As limited slot availability is one of the driving forces behind the selection of multi-lateral wells, conductor sharing is a possible alternative. Experience with both technologies on the Bongkot field has proved that conductor sharing can offer greater operational flexibility than the multilateral alternatives at equivalent costs.

In multi-lateral wells full isolation of the drains requires expensive equipment and complicated procedures. These complexities increase the cost of well construction and increase the risk of partial or complete failure to reach the objectives. With the multi-lateral on production the costs and risks associated with well servicing operations are also higher.

Drains drilled from shared conductors are operated independently during drilling, completion and production phases. Proven technologies can be used at all stages of the well life, minimizing both equipment costs and the risks of failure. Initial well costs are therefore lower while maximizing production flexibility. Well servicing operations are reduced in both frequency and complexity.

To date on the Bongkot field conductor sharing has been used in seven slots for gas producing wells and horizontal oil wells. A multi-lateral well was previously drilled on the field allowing a direct comparison of the two methods. The cost differential of drilling and completing two horizontal wells from a shared conductor and one multi-lateral well was less than 10%.

As a further benefit, the minor initial investment required to convert a slot to a shared slot at the time of the 1st well installation, will in future eliminate the need for costly and risky slot recoveries, in order to tap unproduced reserves reachable from mature fully drilled Work Platforms, hence increasing the amount of recoverable reserves.

The paper describes the principles of the conductor sharing, the perceived advantages over multi-lateral wells and slot recovery, and presents results from multi-lateral, recovered slot and shared conductor wells drilled to date.
Buying and Selling Producing Oil and Gas Properties: The Norms in the Data
Authors: Lohrenz John
Published: December 2007

Data from actual purchases of producing oil and gas properties over the past decade were collected. For each purchase, 5 data elements were captured: (1) Purchase price, (2) Recoverable oil reserves, (3) Recoverable gas reserves, (4) Oil production rate, and (5) Gas production rate. Quantitative norms in these purchase data are shown as well as distributions about the norms. The results are then used to show how comparisons can be made for specific, recent purchases not in the data base against the norms.
Comparing Three Methods for Evaluating Oil Projects: Option Pricing, Decision Trees, and Monte Carlo Simulations
Authors: Galli A. , Armstrong M. , Mines de Paris Ecole des , Jehl B.
Published: December 2007

Option pricing, decision trees and Monte Carlo simulations are three methods used for evaluating projects. In this paper their similarities and differences are compared from three points of view:- how they handle uncertainty in the values of key parameters such as the reserves, the oil price and costs; how they incorporate the time value of money and whether they allow for managerial flexibility. We show that despite their obvious differences, they are in fact different facets of a general project evaluation framework which has the static base case scenario as its simplest form. Compromises have to be made when modelling the complexity of the real world. These three approaches can be obtained from the general framework by focussing on certainty aspects.
Prediction of Short-term Natural Gas Prices Using Econometric and Neural Network Models
Authors: Reiter Doris F. , Economides Michael J.
Published: December 2007

The development of the natural gas industry in the last decade was shaped by deregulation from federal oversight. This created an environment with fierce competition but also highly volatile spot prices, which exposes market participants to a considerable price risk. Risk management becomes vital in such a business environment. An integral part of risk management besides understanding the market’s fundamentals is to develop quantitative models which help predicting gas prices or price changes based on market information. Current price prediction focuses on long-term equilibrium price forecasts, but does not give any information about the day-to-day volatile behavior of spot prices. For long-term delivery contracts this might be sufficient, but for trading on a speculative basis more accurate information about price movements is sought. This paper shows that a solution for day-to-day prediction of spot prices is feasible. The most appropriate models in achieving this task were selected to be an econometric model with lagged variables and a neural network model. As volatility of the spot price is usually higher in the winter and seasonality in the consumption pattern is given, the model was developed based on data for the winter. The performance of both models was tested in a simulated trading scenario and compared to a scenario where perfect prediction quality was assumed. The results showed that both models were profitable during the time span the test was conducted. The neural network showed better results than the econometric model. In comparison to the best case scenario the results were very pleasing. These models can provide a valuable, supportive tool for trading of natural spot gas in a speculative environment.
Scenario Selection for Valuation of Multiple Prospect Opportunities: A Monte Carlo Play Simulation Approach
Authors: Kokolis George P. , Litvak Boris L. , Rapp William J. , Wang Ben
Published: December 2007

This paper describes an approach for simulating and appropriately valuing complex E&P projects containing multiple prospects. The approach uses a Monte Carlo simulation model, which is described, that simulates a play containing multiple prospects. The play evaluated can consist of pure exploration prospects, or may contain a mixture of discovered reserve opportunities (DRO's) and exploration prospects. Resource (reserve) size distributions, dependent geologic prospect risks, risk tolerance, stand-alone commercial threshold sizes, and tie-back thresholds are some of the key drivers of the play simulation.

The simulation generates expected commercial reserve levels and commercial risks for each prospect included in the play, as well as an overall project commercial reserve distribution and risk level. In addition, and more importantly, discrete development scenarios for high (P90), mid (P50), and low (P10) reserve cases can be generated. These development scenarios can then be used to determine a valuation range for the prospects.

The value of this approach is that it provides a consistent methodology to generate a range of discrete development scenarios that span the reasonable range of project success - case expectations. Development plans for those scenarios can then be applied and the scenarios can be deterministically evaluated to determine the range of the project's economic value. This hybrid approach of a stochastic play model combined with deterministic economic evaluations avoids some of the common pitfall of most pure stochastic or pure deterministic approaches.

Methodology is also described for logically grouping discrete prospects into "super-prospects" for the purpose of evaluating projects that contain an unwieldy number of small prospects.
Formation Evaluation Masked by Mud Invasion
Authors: El-Wazeer F. , Haggag M. , El-Farouk O.
Published: December 2007

Mud invasion affects most data acquired by logging tools which in turn affects formation evaluation. Historically, correction programs have been designed to compensate for this effect. With the introduction of Logging While Drilling (LWD) it has became possible to gather data before invasion masks reservoir properties.

Complete logging suites run in a number of wells on-shore Abu Dhabi allowed quantification of invasion effects using logging while drilling, logging while pulling out and wire-line logs. The comparisons, in both horizontal and vertical holes, indicated considerable differences in resistivity and nuclear measurements between runs. The variations depend on time of exposure, porosity, differential pressure and permeability. In horizontal wells where exposure time is longer, resistivity values were greatly reduced by invasion, to the extent of masking true formation resistivity which could not be corrected through known algorithms.

These phenomena may explain differences between log interpretation and test results. In some cases, dry oil was tested in formations that calculated high water saturation, up to 70%, based on logs affected by invasion. It became apparent that the invasion profile had different characteristics in gas zones, providing a new tool for gas detection. In addition, monitoring invasion processes is a useful method for fracture detection by overlaying while-drilling and after-drilling resistivity curves. Fractured zones detected by this method were confirmed by bore-hole imaging techniques. This study proposes a complete framework for evaluating invasion effects leading to improved reservoir description.
Regional Temperature Gradient: A Key To Tilted OOWC
Authors: Stenger B. A.
Published: December 2007

The Arab-D member – Arab formation (Upper Jurassic) – is one of the most prolific oil reservoirs in Saudi Arabia. Located onshore in the Eastern Province and offshore in the Arabian Gulf waters, many huge oil fields have been discovered since the forties. In addition to their size, several Arab-D oil fields present another similarity: the original oil water contact (OOWC) is apparently tilted.

Several theories have been advanced in the past, but none were able to account successfully for the tilt.

The lack of flank wells intersecting the OOWC in a clean reservoir section makes it even more difficult to ascertain the origin of the tilt. In addition, special care must be devoted to avoid using information coming from edging wells in areas where crestal production has already been high, resulting in a dynamic OWC, not the OOWC.

A new model has now emerged to account for the observed tilt of the OOWC. This model is based on the existence of a higher geothermal gradient close to the Dammam dome area (Saudi Arabia Eastern Province). Studies are underway, using SAUDI ARAMCO multi-disciplinary teams to integrate these facts in a tectonic model of the area.

For the Ghawar field, it has been shown that the observed tilt of the OOWC can be explained by the evolution of the regional geothermal gradient, and by an inflow of fresher water on the western flank of the Haradh area. What was thought before to be a hydrodynamic-related tilt is now interpreted as a pure static equilibrium with varied fluid densities.

The tilt of the OOWC has been back calculated and found to be in good agreement with the values measured in key wells. Applications of this particular type of static equilibrium in reservoir simulation will be presented to conclude this integrated approach, which was successful to establish a consistent picture of the Ghawar OOWC tilt.
Case Study: The Role of Simulation in Supporting Reservoir Management
Authors: Al-Yousif A. M. , Al-Hasan A. H.
Published: December 2007

Two newly drilled high slanted wells produced water pre-maturely. The two wells were completed with good clearance from the oil /water contact. Openhole logs of the two wells showed water-free oil zone. Offset wells located downstructure and towards the flanks produced water-free oil from the same zone. Down structure newly drilled conventional well showed a full oil column from the top to the base of the reservoir.

With the above description of the problem, the following questions need to be answered:

How did these two high slanted wells produce water very pre-maturely? What was the production mechanism? Will it be feasible to drill more wells down structure from these two wells and towards the flank? And, if feasible, what type of completion (conventional or high slanted / horizontal) should the proposed wells have?

Simulation was used as a tool to investigate the above-described case in an attempt to give possible answers to the above expensive questions.

The study considered a three-dimensional sector model. The model was finely gridded and multi-layered to provide aerial and vertical tracking of fluid movements required to reasonably assess reservoir performance.

Results of the study: (1) assisted in explaining the early water breakthrough in the two high slanted wells, (2) gave guidance to reservoir management engineers for the proposed future drilling of five wells, (3) recommended optimum rates for the wells in the study.
Pinpointing Fluid Entries in Producing Wells
Authors: Rounce Justin , Lenn Chris , Catala Gerard
Published: December 2007

In recent years there has been significant increase in understanding multiphase flows in producing oil wells. This has shown that evaluation of production can be challenging when conventional production logging measurements are used. Often, only qualitative interpretations can be made, leading to remedial work recommendations based on partial answers, even in vertical wells.

In this paper we summarize the most current understanding of multiphase flows, which have lead to the development of a new production logging measurement and interpretation technique, in which global and local sensors are highly integrated. The resulting new production logging technology has, for example, successfully been conveyed in very high-angle wells, without the assistance of coiled tubing, and major new measurements have been taken as close as 1 ft from the bottom of the well. Furthermore, such technology allows better diagnosis and quantification of even minor, but economically significant, oil entries completely undetectable by conventional production logging tools.

Field examples are presented, demonstrating the value of these new measurements. Unambiguous detection of large- and small-scale oil entries in addition to unwanted water entries with pinpoint accuracy are shown. This leads to confident remedial actions and more accurate evaluation of field economics with better estimation of reserves and sweep efficiency, previously outside the resolution of traditional measurements.
Dimensionless Groups for Interpreting Proppant Transport in Hydraulic Fractures
Authors: Al-quraishi Abdulrahman A. , Christiansen Richard L.
Published: December 2007

The significance of convection, density driven flow, for placement of proppant during hydraulic fracturing has been discussed in the literature. In this study, small glass model was constructed to simulate a fracture. Newtonian and non-Newtonian fluids with controlled density differences were used and variables such as density difference, viscosity, fracture width, proppant concentration, and flow rate were considered. Proppant placement efficiency in the experiments was interpreted with two dimensionless groups. One group compares viscouse and gravity effects and the other compares convective and dispersive effect. The experiments showed that the pattern formed by the boundary between the displaced and the displacing fluids is very simmilar to that observed in much larger models. It has been noticed that convection is very significant even with very small density differences. As viscouse to gravity ratio increases by reducing gap width or increasing the displacing fluid viscosity, the effect of convection becomes less and proppant placement efficiency tends to increase resembling that of Craig et al.1 for gravity override in reservoirs. The effect of convective-dispersive group was found to be small compared to the viscouse to gravity group. The experiments conducted were simulated using an excutable code (GOHFER) and the results indicate that proppant slurry transport can be accurately modeled.
Increasing well life cycle by eliminating the multistage Cementer and utilizing a Light Weight High Performance Slurry
Authors: Mukhalalaty Talal , Al Suwaidi Abdullah , Shaheen Mansour
Published: December 2007

Trapped gas and oil between production and intermediate casing (abnormal annulus wellhead pressure) has been globally recognized as one of the serious challenges facing drilling and production operations. The issue is becoming serious since wells are aging and the integrity of the casing portion below well head is increasingly affected by the shallow water corrosive environment. The potential safety and environmental hazards of the abnormal annulus pressure, have encouraged ADCO to review the current drilling and cementing practices, aiming at minimizing the impact of the problem, thus improving well life cycle and reducing the frequent work-over interventions. The general guide lines set to resolve the problem were by eliminating potential leakage paths in the completion and casing strings, and by emphasizing on the quality of the primary cementing, specially of the production casing string.

Cementing casing in single stage utilizing lightweight slurries has been the technique used in ADCO to improve 9 5/8" primary cementing. The new cementing methods have been found operationally and economically feasible. Summary for the recent case histories are presented in this paper, along with the conclusions and recommendations.
Rotary Drilling US-Khuff Formation with PDC Bits
Authors: Salman Moh'd , El Raggal H.
Published: December 2007

Over the years in the Arabian Gulf Offshore Khuff gas wells have been drilled by turbodrilling technique in both 12 ¼' and 8 ½" hole and proved to be more economical and reliable compared with the application of rotary drilling with roller cone bits. However, bit sticking problems were experienced while the turbine was in the hole in most of the deep Khuff wells, resulting in fishing job or sidetracking operations.

A total of fifteen major occasions were quoted, more than half of them took place while making a drill pipe connection. The bit was the sticking point, in view of the facts, that it was possible to circulate and rotate with the turbine.

Operating company Adma-Opco's solution to this drilling problems, involved the use of new TSP or PDC bits technology combined with new turbine stabilization and the use of new PDC bits design and features on rotary drilling. The drilling performance that is analyzed in this paper, highlights the following:

Use of successful bit design as well as new bit technology and features in combination with turbine and on rotary assembly. Impact of new PDC cutter technologies on bit life and rate of penetration. Torque and vibration with PDC bits. Hydraulic requirements for PDC bits in deep well application. Influence of PDC cutter size on performance when drilling Khuff formation.
Influence of Temperature and Interfacial Tension on Spontaneous Imbibition Process
Authors: Chimienti M. E. , Illiano S. N. , Najurieta H. L.
Published: December 2007

Spontaneous imbibition is a mechanism that can significantly contribute to the production rate and final oil recovery in fractured and stratified reservoirs.

This mechanism is affected by rock and fluid properties and it has been reported by several authors to be strongly dependent on interfacial tension (IFT) and contact angle. Both magnitudes are influenced by system temperature.

In this work a laboratory study is performed on the influence of IFT and temperature on production rate and oil recovery for a given rock-fluid system. All sequences were performed on rock and fluid samples from Argentine basins. Rock samples were of medium permeability (56.1 to 83.1 mD) and porosity ranging from 18.7 % to 22.9 %. The fluids used were formation water and medium viscosity oil (45 cp at standard conditions). The samples were carried to irreducible water saturation before performing the imbibition tests resembling the assumed reservoir condition.

Initial tests were designed including representative water, oil and rock samples at several temperature levels. Another sequence of tests were performed with the addition of variable amounts of water dispersed surfactant. A noticeable influence of experimental conditions was found on the final results. As part of the tests, the same final temperature was reached through single and several steps observing the differences in overall performance.
SAGD, Pilot Test in Venezuela
Authors: Mendoza Humberto A. , Finol Jose J. , Butler Roger M.
Published: December 2007

PDVSA, began its first pilot test of a steam assisted gravity drainage (SAGD) production system in Latin America during June 1997. The "dual well" SAGD process requires the horizontal drilling of two wells one above the other. The upper well is dedicated to injecting steam in a continuous form and the lower to produce the reservoir fluids.

The pilot test was carried out in the Tia Juana Field, Western Venezuelan, where reservoir fluids are highly viscous (typically 20,000 cp. under reservoir conditions). Reservoir depth is approximately 1000 ft with a porosity of 38% and a permeability of 1-2 darcies. The pilot wells consisted of two pairs of infill wells within an original seven spot pattern with a well spacing of 231 meters.

The planning and implementation of the test was done between June and December 1997. Production started on December 15, 1997. The drilling stage of the pilot required the use of a "Magnetic Guidance Tool" (MGT) to drill the horizontal wells with a 5 meter distance between producer and injector along the horizontal section.

The paper shows pressure and temperature data acquired during the SAGD process from both conventional single point gauges and the latest generation of fibre optic distributed temperature measurements providing real time thermal profiles along the complete well bore.

The production results during the first year of operation show an average production of 700 bopd, which is above the initial production expected. This performance is promising, and it is expected that the initial objective of 60% recovery in the pilot area will be reached approximately 3 ½ years from the onset of production.

During the first year of production, a history match was performed using the Stars simulator. The comparison of real and simulated production shows close agreement and a final recovery in the order of 60 % of STOIIP has been estimated.
Effective Pay Zone Isolation of Steam Injection Wells
Authors: Blanco A. , Colina A. , Rodríguez W. , Bolívar R.
Published: December 2007

The steam injection process is on of the main methods for enhanced recovery of heavy and extra heavy oil in shallow reservoirs. The cementing of such wells has conventionally been performed using a Portland cement slurry formulated with silica flour to prevent retrogression in compressive strength. The main disadvantage of this type of slurry is the incompatibility between the cement and mud system which results in problems of channeling an microannulus around the casing. Additionally, thermal stresses caused by the steam injection process affect th development of physical properties of set cement increasing permeability and decreasing casing – cement bonding. This paper shows the results of field applications of a new technology t isolate steam injection wells, based on blast furnace slag. Th new technology provides a cementing system that is compatibl with mud, has low permeability, is expansive and develops stabl mechanical properties during and after the steam injection process. These characteristics assure the zonal isolation of pa zones and offer potential incremental improvement to the stea injection process compared with conventional technologies.
Predicting Temperature Profiles in Producing Oil Wells Using Artificial Neural Networks
Authors: Farshad F. , Garber J. D. , Lorde J. N.
Published: December 2007

The prediction of flowing fluid temperature profiles in producing wells has become necessary in several design problems that arise in oil and gas production. The accurate prediction of temperature drop due to flow in oil or gas wells is required by engineers and scientists for many design calculations including developing programs to optimize deliverability of wells1, designing artificial lift installations2 and characterization of corrosion3. In addition, existing multiphase flow correlations require PVT data of the wellbore fluid which are temperature-dependent parameters.

Many correlations to predict temperature profiles of the wellbore fluid, for single-phase or multiphase flow, in producing oil wells have been developed using theoretical principles such as energy, mass and momentum balances coupled with regression analysis.

This paper presents a novel approach of using artificial neural networks (ANNs) for predicting temperature profiles. Two artificial neural network models that predict the temperature of the flowing fluid at any depth in flowing oil wells were developed. Backpropagation was used in training the networks. The networks were tested using measured temperature profiles from seventeen wells in the Gulf Coast area. The neural network models successfully mapped the general temperature-profile trends of naturally flowing oil wells. The better of the two models predicted the fluid temperature with a mean absolute relative percentage error of 6.0%.

The accuracy of the proposed neural network models to predict the temperature profile is compared to that of existing correlations. The neural network based model in this study exhibits significantly lower mean absolute relative percentage error than other correlations. Furthermore, in order to test the accuracy of the neural network models to that of the Kirkpatrick4 correlation, a mathematical model was developed for Kirkpatrick4 flowing temperature gradient chart.
Asset Based Technology Planning
Authors: Ungredda Alessandro , Carrasquel Aminta , Romero Edgar , Alfonzo Alvaro
Published: December 2007

As a means of enabling Petróleos de Venezuela's (Venezuelan State Oil Company), continuous quest for optimal business opportunities within its E&P operations, a Process has been designed and adopted for the Planning and Implementation of its R&D and Technology Effort. Said process, which has been adequately learned by the Corporation, aims at materializing value creation opportunities starting from a comprehensive matching of business needs and new technologies. As a second step, the process determines a close collaboration between Technology Organizations and the Operator Units in order to properly evaluate and transfer new technologies into their ongoing operations. Accurate understanding of current and future operation conditions, is the most important element to assure commitment from both groups.

A correct framing of the business case, including risk assessment for each proposed technology, secures high level support for the whole effort. Provisions are made to implement Projects for the proper integration of available and proposed Technologies for the optimum exploitation of each Asset. As a result each project reduce required time for the transfer and deployment of new technologies by the Asset Units thus materializing the optimum value for the Corporation.

The whole Technology Planning process here described has been fully integrated with the ongoing Business Planning and Budgeting system assuring its alignment with the main issues and needs that guide Short and Long Term vision of PDVSA's E&P business, therefore assuring proper funding and support for the Technology effort needed to achieve them.
Managing the Evaluation of Improved Oil Recovery Technologies
Authors: Mogollón J. L. , Romero L. , Cohen L. Anselmi
Published: December 2007

In the last five years PDVSA has dedicated a big effort to develop and evaluate new technologies in order to improve light-medium oil recovery factors, by optimizing: mobility ratio, surface tension and water conformance. As result of this, more than 50 wells have been treated with gels. Also, pilot tests of WAG and ASP are on schedule and a new technology to improve vertical sweep efficiency, by placing emulsion, is on testing. This situation contrasts with that of the previous 15 years, when no new EOR technology was tested in a Venezuelan field.

The process to evaluate a new technology is rather complicate, even for those technologies already proved by other companies. In this paper, the methodology used is exemplified through the scheme followed to evaluate the emulsion technology. The development started after the problem-opportunities analysis and establishment of the possible competitive advantage pointed that: i) a key problem of the oil industry was been addressed, ii) the process has clear success probability, and iii) the basic infrastructure and qualified human resources were available. A flat administrative structure, divided into 3 technical functional areas, was selected. The keys for the results obtained to the date are the integration of multidisciplinary teams, the continuous communication and the participation of potential users.

Among the barriers found, it is worth to mention the difficulties to start the fluently communication among disciplines and the right timing of the professional participation. In order to surpass them, technical leadership together with the appropriate management was necessary. The availability of an Intranet facility helped to disregard the geographical location problems in many cases.
Large Scale NOW/NORM disposal through slurry waste injection
Authors: Baker Brian D. , Englehardt John M. , Reid James D.
Published: December 2007

It has been established that large scale NOW/NORM (Non Hazardous Oilfield Waste/Naturally Occurring Radioactive Materials) disposal can be accomplished through SWI (Slurry Waste Injection). This process involves excavating the disposal site, mixing the material into the slurry with a resulting composition of 40% solids. The slurry is then pumped at or above fracture gradients into a suitably characterized reservoir. A series of fractures are created forming a sphere around the perforated interval. These fractures constitute the "disposal domain"1 which grow at different orientations around the wellbore. Due to the plastic nature of Louisiana sandstones (at shallow depths <5000 ft), these "fractures" are not necessarily the vertical fractures associated with oil/gas production but more like capillary tube pathways into the formation. This process was accomplished by Chevron in the CP2 sand at Port Fourchon in Louisiana. The objective was to clean up a surface contaminated site (approximately 400 000 bbls). The results will show that this methodology is economic and environmentally safe. By duplicating this technology, other large surface non-hazardous oilfield waste sites may be remediated.

The SWI process involves cyclic injection12 of the slurry (30–40% solids) at 15 – 16 BPM with injection BHP (bottomhole pressure) of 3900 psia for a 12-hour period. Injection is then shutoff overnight and the fractures heal. The process is similar to a continuous tip screenout for each injection period and creates a disposal domain1 in the target sand. This paper describes this injection procedure, disposal reservoir selection and characterization, process variables, applicable models for multiple fractures, matrix injection (capillary tube type waterflooding model), wellsite data monitoring, pressure transient analysis and logging technology to show fracture containment. Also described are some of the current environmental concerns19 and typical permitting issues (State and Federal) associated with the process.
PVC Line Pipe for Conveying Oil Cuts Operating Cost
Authors: Barboza C. A. , Mata A. C. , Villamizar C.
Published: December 2007

This paper shows the results obtained in a field experience developed at the "Campo Ruiz", Valle de La Pascua, Venezuela, where a polyvinyl chloride (PVC) pipeline was used to convey oil down stream of the well with pressures up to 70 psi and temperatures below 90°F. It is also shown the potential for this type of application in Venezuela. The American Petroleum Institute provides standards for polyvinyl chloride (PVC) line pipe suitable for use in conveying oil, in the oil and gas producing industries (API 15LP). Pipe dimensions schedules and pressure ratings listed in these standards correspond to important applications used in these industries, and can be found down stream on the well, from the well head to the flow station. The reported values of our interest are pipelines from 3 to 6 inches of diameter and pressures ranging from 130–160 psi at 73°F (23 °C) to 65 – 80 psi at 120°F (49 °C). According to their chemistry nature, thermoplastic pipelines have certain advantages over the traditionally known metallic pipelines in corrosive environments. Additionally, its fit to mention factors as lower costs by meter, as well as lower costs in handling and installation. The development of this application in Venezuela, within the ranges specified by The American Petroleum Institute, could solve some corrosion problems and lower replacement costs.
Use of effective properties for characterisation of a naturally fractured reservoir in East Venezuela
Authors: Boardman D. W. , Porjesz R. , Cabrera J. R.
Published: December 2007

This paper present the results of an integrated reservoir characterisation study, and the methodology used to confirm the existence of an additional reservoir drive mechanism based on natural fractures, which has been used to explain the significant discrepancies between material balance and volumetric estimates of STOIIP.

A detailed core-based sedimentological study has defined the depositional environment and facies connectivity. Core, log, drilling and production analyses have been integrated to provide information on the natural fracture network, and geomechanical interpretation has been used to prove that the fractures seen in core are natural, and to explain the impact of regional stress variations on fracture properties and flow performance. Effective parameters have been estimated to represent the fracture network in the simulation model.

A non-stationary geostatistical simulation has been used to model the reservoir facies distributions, and the static model has been conditioned with interpreted DST permeability, to represent effective flow properties. A full field history matched simulation model has been used to confirm STOIIP, and to develop an exploitation strategy.
Analysis of Well Performance with Multiple Shut-in Periods
Authors: Helmy M. Wael , Wattenbarger R. A.
Published: December 2007

This paper presents a technique for the analysis of monthly production data of wells subjected to periodic shut-ins, and with limited downhole pressure data. The frequent shut-ins cause severe scatter in the monthly average rate, which hinders the analysis using conventional methods (specializedplots, deconvolution, etc..). We present an application of the superposition principle to identify an analytical reservoir model that gives a pressure response similar to that observed in the field. The model is then used to "filter-ouť" the scatter in the average production rate data, and construct a production trend without the effects of the shutin periods. The model and constructed trend are used to locate reservoir boundaries, calculate reservoir parameters and estimate the original hydrocarbon in place. Two field examples are given to illustrate the validity of the proposed method.
New Method of Analyzing the Pressure behavior of a Well Near Multiple Boundary Systems
Authors: Ispas Valentin , Tiab Djebbar
Published: December 2007

The accuracy of well test data interpretation is critical in obtaining several reservoir properties, such as permeability, porosity, drainage area, and well location. Well test analysis can be complicated by wellbore storage, skin, and especially by the presence of flow or no-flow boundaries in the system. Therefore, different methods for interpretation of the effects of reservoir shape and well location on wellbore pressure have been presented in the petroleum literature.

Starting with the use of the image method and conventional semilog interpretation technique developed in the 1950's, well testing analysis techniques have progressed rapidly by the introduction of the pressure derivative approach in 1976.

The present study uses two analysis techniques for interpreting the pressure and pressure derivative behavior for a well in multiple boundary systems, including wellbore storage and skin effects1. First, a type-curve analysis is performed using computer generated type-curve plots for different reservoir shapes and boundaries, such as (1) Well between two intersecting boundaries; and (2) Well between two parallel boundaries. The output results of the type-curve analysis are then used to develop a comprehensive technique of analyzing the well test data without type-curve matching, based on the Tiab's Direct Synthesis Technique18.