bluuebunny/crossref_metadata_2025 huggingface dataset:
Study of the Lifting Technology for Numerical Control Reciprocating Electric Submergible Pump
Authors: Wang Dejin , Wang Zaishan , Lu Dongfeng , Ji Shengzhu , Hou Weiqian , Ge Dongyuan , Guo Shiying
Published: December 2007

Now, the technology of pumping unit-deep well pump is widely used in Daqing Periphery oilfield. But the average system efficiency is only 7.8% because of the deep of the well, the consistency of the oil and the low output of each well. The main reason of changing the deep well pump is broken off, separated and deflected abrasion in the upside of plunger and rod system. It is about 30.4% in all operating wells in 2004 and 32.8 percent in 2005 in NO.8 Oil Production Company. It leads to high cost in production and affects the economic benefit.

Research content:

This system is composed of direct current electromotor, frequency conversion control system and suitable pump. The stator of direct current electromotor is connected with the tubing underside of the pump. The rotor drives the plunger of the pump to reciprocate along axial way(direction) to lift the oil. The control system on the ground can change the pump speed to regulate the theoretical discharge capacity.

Laboratory experiment:

Place the electromotor into the oil which temperature is 60°C and pressure is 25Mpa, the insulating resistance is 2500MΩ after 240 hours. Simulating the real well with the 28mm pump until the pressure of well-head is 40Mpa, which is equivalent to 2.3t lift power. When the pressure of the well-head is 20Mpa, the pumping efficiency is 81%.

Field experiment:

There were 10 wells in this test in August 2004. The pump setting depth was about 1450m. The daily production was 5.7m3. The pumping and system efficiency was 82%, 31%, respectively. It can economizes about 27% in investment, 30% in run cost and 50% in power compared with the cross-model pumping unit.

Conclusion:

This technique adapts to the well which production is below 20t. It is a substitutive pumping unit for the low production, middle or deep wells. This technique need not pump rod to transmit power. It can reduce the lost of stroke, increase the pumping and system efficiency and decease the repairing cost which is caused by pump rod. Because the cluster direction and horizontal wells are increased year by year in Daqing Periphery Oilfield, this technique can lift the oil in each deep due to non-rod transmission.
Burning Reserves for Greater Recovery? Air Injection Potential in Australian Light Oil Reservoirs
Authors: Hughes B. L. , Sarma H. K.
Published: December 2007

Air injection is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Analogy with successful air injection projects in the USA, suggests that it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date.

Using open file data, high level screening criteria are used in this study to identify prospective petroleum basins, and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the technique are discussed, as are directions for implementation in Australia.

Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crude, consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon (HC) miscible floods, freeing cleaner HC gases for energy use. Ideally the process is suited to deep, high-temperature, light oil reservoirs, and is applicable to both secondary and tertiary recovery.

The Cooper-Eromanga Basin, Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A’ in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection.

Given the ‘high’ oil price and maturity of Australia's oil provinces, significant value is associated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and consideration as an alternative to accepted EOR techniques.
Hydraulic Fracturing of Miocene and Oligocene Sandstones in the Taranaki Basin, New Zealand
Authors: Green D. , Seanard K. , Martin A. N.
Published: December 2007

The Taranaki district of New Zealand, located in the southwest corner of the North Island, is the center of the country's emerging oil and gas industry. Over the last five years, an active campaign of propped hydraulic fracture stimulation has been performed in the early Miocene and Oligocene sandstones, located towards the south of the Taranaki sedimentary basin. Although hydraulic fracture stimulation is relatively rare in New Zealand, it has shown itself to be highly effective. This is due, in part, to the application of sound scientific and engineering principals, rather than the stochastic approach that is often applied when fracturing. The formations themselves are highly complex and consequently the techniques used for fracturing are at the cutting edge of today's fracturing technology. The results of the programme have significantly benefited from this methodical and progressive approach.

This paper deals with the various aspects of fracturing into these formations and the lessons learned, including the equipment and methods used. It also details how the methods have evolved and allowed treatments to increase in both size and effectiveness, using numerous case histories. These detail what can be achieved in an area that is generally unfamiliar with the processes involved, when an existing technology is systematically applied.
Formation Damage Induced by Fracture Fluids in Coalbed Methane Reservoirs
Authors: Chen Z. , Khaja N. , Valencia K. L. , Rahman S. S.
Published: December 2007

This paper presents the results of a laboratory study on the effect of different fracture fluid systems on permeability impairment of a typical coalbed methane (CBM) reservoir. These fluid systems include conventional gel fluids (linear and cross-linked gel), gel fluid with surfactant and a viscoelastic fluid system. A series of flow tests on coal plugs were conducted under simulated reservoir conditions to assess permeability reduction due to matrix swelling and cleat plugging by gel fluids. Tests included surface behavior of different fracture fluids and surfactants on coal surface, degrees of matrix swelling and plugging of fractures and cleat systems by fracture fluids.

The results of these tests have shown that permeability impairment induced by matrix swelling is highly irreversible. This irreversible damage can be prevented to a certain extent by conventional practices of adding certain types of salt (such as KCl) into fracture fluids. Both linear gel and cross-linked gel fluids cause a significant reduction (around 70%) in permeability of CBM reservoirs. Addition of KCl along with certain types of surfactants to gel fluid can marginally improve gel clean up. However, the permeability impairment could be as high as 60%. With the use of viscoelastic fluid system, on the other hand, permeability impairment can be as little as 20 to 30%. This means the viscoelastic fluid system has a great potential in reducing permeability impairment which in turn can help rapid dewatering from CBM reservoirs and increase production.
Developing a Fractional Flow Curve from Historic Production to Predict Performance of New Horizontal Wells, Bekasap Field, Indonesia
Authors: Sitorus J. , Sofyan A. , Abdulfatah M. Y.
Published: December 2007

A fractional flow curve (fw versus Sw) is used to describe the immiscible fluid displacement process. Developing a representative fractional flow curve for a specific reservoir can be quite challenging when fluid and special core analysis data is limited. This paper demonstrates a technique to develop a reservoir scale fractional flow curve from historic production data. The curve becomes the basis for an analogous model that allows the estimation of oil rate production forecasts and reserves for existing or proposed new wells. In addition, relative permeability curves can be generated based on the resultant fractional flow curve. A comparison with relative permeability curves obtained from special core analysis can be made to provide increased confidence.

In order to develop an fw (water cut) versus Sw (prevailing water saturation) relationship from historical production data, a simplified material balance algorithm and the Corey equation are solved simultaneously. A number of iterations are made until a reasonably good match is achieved. In waterfloods and strong water drive reservoirs, the total fluid production rate can be assumed constant. Therefore, it is possible to estimate the future oil production rate profile for new or existing wells using the reservoir scale fractional flow curve.

The results compared favorably with forecasts developed using our in-house simulation model and commercial material balance software with less time and effort. This method was successfully used to examine the performance of over 30 horizontal wells in the Bekasap field. The method also served as a simple preliminary tool to identify in-fill development well opportunities in the Menggala South and Waduk fields, two other mature oil fields in Sumatra, Indonesia.
Innovative Use of Expandable Sand Screens Combined With Propped Hydraulic Fracturing Technology in Two Wells With Intelligent Completions in the Egret Field, Brunei: Challenges, Successes, and Best Practices Learned
Authors: Abdul-Rahman Sakamrin , Lim Derek , Lim Jit Juan , Ong Kuo Chuan
Published: December 2007

Oil and gas producers have long been looking for effective sand control methods that allow completion flexibility and improved productivity throughout a well's lifecycle. This paper discusses the many challenges encountered during the planning and completion of two wells in the Egret Field in Brunei, operated by Brunei Shell Petroleum (BSP), how the challenges were addressed, and the best practices identified for future operations.

Sand-control techniques such as an extension packing and hydraulic fracturing were evaluated to help minimize the risk of fines plugging because of the high fines content (10 to 15%). To minimize well interventions while maximizing data gathering, an intelligent-well completion using surface-controlled sub-surface variable chokes for internal gas-lift and surface controlled sub-surface fixed chokes was proposed.

Another design challenge was that conventional wire-wrapped screens would have insufficent clearance to accommodate intelligent-well completions. A feasibility study recommended a combination of expandable sand screens (ESS) and propped hydraulic fracturing in a cased-hole environment.

Two wells were planned in which three oil reservoirs would be completed and produced commingled, using one gas reservoir as a lift gas source. Expandable sand screens would be installed across the perforated intervals inside a cemented 9-5/8-in. casing.

With a skin of less than +1 on all completed intervals, the productivity of both wells has been excellent. The success has been attributed to the unique combination of ESS and hydraulic fracturing.
One-Molar Salt Solutions Used for Clay Control in Water-Based Frac Fluids in Western Siberia
Authors: van Gijtenbeek Klaas , Neyfeld Alla , Prudnikova Antonina
Published: December 2007

The use of oil-based fluids in the western Siberian oil industry for hydraulic proppant-fracturing treatments in water-sensitive formations to prevent clay swelling was widespread. The added advantage of using oil-based fluids for cold weather conditions is obvious. However, with the growing number of treatments and increasing treatment sizes, the use of oil or diesel, from an economical point of view, becomes less attractive. In addition, there is a growing environmental concern with respect to using oil for mixing and pumping fracturing fluids. The use of gelled water is cheaper, and from an environmental perspective, more attractive.

The addition of 2% KCl to water-based fracturing fluid for temporarily controlling clay swelling is widely accepted as a standard practice. In situations where water-sensitive sandstone formations have been treated and longer protection has been required, very often additional clay stabilizing agents are added to the water-based fracturing fluids.

Research on the technology of matrix acidizing treatments has revealed that the use of 2% KCl transforms into 1.5% saltwater as a result of ion exchange. The 1.5% saltwater solution is too weak to prevent clay swelling. Clay swelling can be prevented using a 1 molar (7%) KCl salt solution.

Based on acidizing treatment research, it was decided to use 7% KCl as a temporary clay control additive in water-based fracturing fluids for treatments in western Siberia. One-molar salt solutions have been used for all the treatments performed during the last four years. Model 50 viscometer measurements were made to identify the influence of increasing KCl concentration from 2% to 7% on the viscosity development of borate crosslinked fluid. Water retention problems have not been reported since 7% KCl has been used.

From a study of the pre- and post-fracturing production data, it was apparent that in general the percentage of water produced with the oil did not reduce. It is postulated that this is an indication of good temporary clay control. This study excluded treatments that clearly contacted a water-bearing zone.
P/Z Abnormally Pressured Gas Reservoirs
Authors: Ramagost Billy Paul , Farshad Fred F.
Published: December 2007

The P/Z versus cumulative gas production plot is a commonly accepted method used to obtain original gas in place in volumetric (no water drive) gas reservoirs. Many petroleum engineers apply this method to abnormally pressured reservoirs which can lead to errors of up to 100% in the original gas in place extrapolation. The problem is that the conventional P/Z plot in abnormally pressured reservoirs must be adjusted for rock and water compressibility to obtain reasonable estimates of original gas in place.

A normally pressured reservoir will have an initial pressure gradient between 0.43 and 0.50 psi/ft. Reservoirs with pressure gradients greater than this are abnormally pressured. In the Gulf Coast area of Louisiana and Texas, pressure gradients can be very close to overburden pressure gradients with some of the gas reservoirs having gradients of 0.85 psi/ft. or higher.

In abnormally pressured reservoirs the reservoir fluids support additional pressure as is evident by pressure gradients of 0.85 psi/ft. The gas compressibility can actually approach formation compressibility in abnormally pressured reservoirs. This makes it important to include both formation and water compressibility in the P/Z plots when trying to estimate original gas in place in abnormally pressured reservoirs.

This paper presents a new technique for predicting performance of an abnormally pressured gas reservoir. This method maintains the old straight line relationship for conventional P/Z's in normally pressured reservoirs and allows direct extrapolation of original gas in place in abnormally pressured reservoirs by accounting for rock and water compressibility in the adjustment factor term. Thus, in abnormally pressured reservoirs, the early prediction of original gas in place from the P/Z curve is one of the main reasons for using this method.

This method has been successfully applied to three abnormally pressured reservoirs. They are the North Ossun Field in Louisiana, the Anderson "L" gas reservoir in South Texas, and to a Louisiana offshore gas reservoir. The results of the application of the new method and a comparison of predicted performance in abnormally pressured reservoirs using this technique and the conventional P/Z method will be presented in this paper.
Identification, Origin, and Distribution of Tarmats in Upper Zubair Sand Reservoir, Raudhatain Field, North Kuwait
Authors: Azim Shaikh Abdul , Al-Anzi Salah , Hassan Yahya , James Stephen , Mandal D. , Al-Ajmi Hamad
Published: December 2007

The Upper Zubair Formation is a giant reservoir consisting of 350 ft of excellent quality sandstone. This main producing reservoir has a 100 thick tar mat historically encountered near oil water contact. Recently, a well completed in the crestal part of structure above tar mat zone and in good quality sand did not contribute to oil production and presence of tar was suspected. A re-look at identification, origin and distribution of the tar mat has become critical for formulating future development strategy of the reservoir.

An appraisal well was drilled on the crest with a comprehensive data acquisition program including coring, fluid sampling and logging. Geochemical analyses of core plugs at every 4 ft were carried out along with fluid invasion studies. Observation from core material was compared with NMR logs to formulate criteria for identification of tar zones to supplement information from open hole and cased hole logs.

NMR transverse T2 relaxation histogram was observed to be affected by fluid properties and poresize distribution. There is a consistent shortened T2 distribution along tar mats resulting in missing porosity compared to neutron-density derived porosity. Geochemical analyses of core material indicates high asphaltene zones having undegraded paraffin and are isotopically lighter with immature biomarkers and higher concentration of aromatics. The observations indicate early origin of tarmats due to biodegradation of immature oil at a lower reservoir temperature. Later, undegraded oil with undegraded paraffin profile has migrated in to the reservoir after biodegradation process has ceased.

Biodegraded early origin of tarmat can not explain areal distribution over the field. Local compartmentalization of tar mat from light oil leaking along faults leaving behind heavier fractions during geological history is the possible origin for tar occurring above tar window. Early high Asphaltene content from immature charge, Asphaltene precipitation due to later light oil migrating to trap and gravity segregation explains the occurrence of tarmat in tar window near oil water contact. Early charges/asphaltenes were bio-degraded and incorporated in the tar zone.

Current study helps in identifying and mapping the tar and heavy oil zones in the reservoir. Distribution of tar mat of diverse origin needs to be understood well in advance to have realistic estimation of movable hydrocarbon.
From Justification to Selection: An Automated Supervisory System for the East Vacuum Grayburg-San Andres Unit
Authors: Krusen Leslie C.
Published: December 2007

Phillips Petroleum Company, as operator for the East Vacuum Grayburg-San Andres Unit, has included an innovative automated supervisory system in the unit's development plan. The system, featuring redundant minicomputers, approximately 200 microprocessor-based RTU's, UHF-radio communications, automatic well testing, and local pumpoff and injection controllers, will increase Unit profitability by improving operation and management of the enhanced recovery project.

Since supervisory systems are a relatively new form of production technology, considerable attention was given to economic justification. After the state of the art was surveyed, constraints upon the system and system functions were determined. The supervisory system was then conceived of as four subsystems; wellsite, satellite, central battery, and command; related both to the production equipment that was to be monitored and the information that was required. The system was let, with installation scheduled for second-half 1981. This paper describes Phillips' path, from supervisory system justification to selection, as a guide to other operators who are considering such a system.

Some of the system's pumpoff controllers, injection controllers, and well test panels have already been installed. Preliminary results are encouraging, although there have been unexpected problems that are currently being resolved. Both are presented, to provide other operators with the benefit of Phillips' present experience.
Performance Resolution Between Variant Rock Bits From Field Drilling Data
Authors: Newcomb Alan L.
Published: December 2007

Rock bit development projects require reliable techniques for evaluating field test data. Differences in performance are determined by using comparison methods in combination with criteria for data acceptance. The main objective is to field test an experimental feature involving the cutting structure, seals, lubricant or bearing of a rock bit and determine its related improvement in drilling performance. Drilling performance is defined in terms of drilling duration and rate of penetration. Performance resolution of small differences relies on the use of simple statistics and rock drillability methods to interpret the test results. These test results form a decision basis for incorporating the experimental feature into the product.
Analysis and Design of a Deep Reservoir, High Volume Nitrogen Injection Project in the R-1 Sand, Lake Barre Field
Authors: Haag James W.
Published: December 2007

An expansion of a low volume gas injection project in the R-1 Sand, Segment G in the Lake Barre Field was investigated. Computer modeling shows that over five million barrels of oil can be produced. Challenges to project startup include drilling and reworking deep wells and the acquisition of a high pressure nitrogen source built on a semisubmersible concrete barge.
Preventing Mud Losses by Wellbore Strengthening
Authors: Song Jae H. , Rojas Juan C.
Published: December 2007

Until recently, the drilling industry had an established range of options for dealing with lost circulation that included pre-treatment with lost circulation material (LCM) and/or remediation with LCM when losses occurred. This paper describes a fully engineered approach taken by BP and Halliburton to formulate a drilling fluid that can effectively strengthen the weak wellbore while drilling. The approach, called Stress Cage theory, is an extension of a lost circulation strategy that has been used for years in the drilling industry. However, it includes using log analysis to identify potential fracture location and determine its geometry, especially its width, and then identify a mixture of particulate materials to seal the calculated fracture width. The application of the appropriate mixture of materials can effectively increase fracture gradient (both in land and offshore), allowing the operator to drill through a weak formation pressured zone successfully with minimal to zero downhole losses. Case histories including drilling parameters, formation pressures, field and laboratory fluids testing, and some of the operational challenges are detailed. The estimated value of Stress Cage applications for BP in 2004 and 2005 has been calculated at $100MM.
Simulation of Gas/Oil Displacements in Vuggy and Fractured Reservoirs
Authors: Kossack C. A.
Published: December 2007

The presence of vugs in a naturally fractured reservoir can be a significant source of reserves. These vugs can be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system. The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators since triple porosity system "isolated vugs" are not part of the formulation.

The simulation of oil production from triple porosity reservoirs requires the development of composite porosity, composite relative permeabilities and composite capillary pressure relationships. These composite curves can be generated from properly designed laboratory experiments on representative cores or by history matching fine grid single porosity simulations. Kossack, et al1 discussed this for water-oil systems. Since the displacement of oil from vugs by gas involves very different mechanisms from water-oil systems and is very complex, the simulation of this process must be studied separately.

This paper describes a numerical scale-up technique to provide the composite properties and curves to be used in gas-oil displacements in triple porosity systems. Displacements in dual and triple porosity gas-oil systems are dependent on the magnitude of gravity and viscous forces, capillary pressure in the matrix rock, composition of the injection gas, and rate of component diffusion in the porous media. Fine grid single porosity simulations are made with a compositional simulator to determine the rate of oil recovery from the fractures, matrix rock, and vugs. These results are then matched with dual porosity compositional simulations, which create the composite matrix properties.

These composite properties can then be used in full field dual porosity simulations of fractured and vuggy reservoirs to correctly predict the oil recovery. The process described can be applied to any triple porosity reservoir where gas is invading the fracture-matrix system.
The Dangers of Volumetric and Financial Data Silos in E&P
Authors: Hull R.
Published: December 2007

Introduction

E&P companies struggle day to day with many challenges. With high oil prices, their primary focus is to effectively produce sufficient hydrocarbons to meet public requirements. With this in mind, data has become an area which has exploded. Now we see that the individuals are overwhelmed with the shear volume of data that is literally at their fingertips. During this time, the Sarbanes and Oxley act has resulted in the realization amongst E&P Company Management, that their popular solutions such as spreadsheets and home grown applications, contain errors which profoundly impact their financial bottom line. Many companies have found out "too late' just how bad these errors are.

In Cost/Schedule Integration

A Process for Project Management By: Ruthanne Schulte, she gives illustrations of how disparate systems can present a challenge.

"Two Products for Cost and Scheduling That Are Not Integrated

Many organizations use two or more products that are not integrated. When the cost and scheduling systems are not integrated, there are numerous drawbacks: They require dual data entry and therefore are cumbersome to maintain and have a high probability for error in the data entry phase.Non-integrated cost and scheduling systems can produce different results.Report verification is difficult due to the lack of an audit trail between the systems.Separate, non-integrated systems are often maintained by different people who report to different supervisors. Agendas may vary and communication gaps occur frequently. Significant discrepancies, and the results thereof, commonly occur in a non-integrated system.

There are positives and negatives for both spreadsheets (internal systems) and commercially developed systems. When a company is given a choice between the two, internal systems provide the benefit of being tailored to the company's specific requirements whilst a commercially developed system may not address these specific company needs. Also, an internal system can be edited and manipulated to continue to meet the ongoing needs of the organization. However, often staff does not have the experience or expertise to deal with these internal systems. A commercially developed system is often more user friendly. Companies need to weigh up these factors and decide the area in which they want to put their time and money towards; homegrown applications or commercially developed solutions.
Long-Interval, Open-Hole Gravel Packs
Authors: Gottschling John C. , Legan Thomas L.
Published: December 2007

For control of formation sand production in California oil wells, the technique of open-hole viscous gravel packing is now being considered for long intervals of 1,500 feet to 2,000 feet. To effectively apply these high viscosity, high gravel concentration slurry packs, the designs and procedures used for the more common, short-interval treatments can he adopted if they are modified. A complete, step-by-step procedure for this technique and the pros and cons of various tools and methods are presented in this paper. Also, 13 case histories were chosen from among several hundred California slurry pack jobs for investigation. Case history data indicates that long-interval, slurry-pack completions are most successful when several considerations are taken into account. Among these considerations are (1) the effects of pack settling when choosing liner design; (2) the need of whether or not to use a seal bore and a lower, tell-tale screen; and (3) the percentage of calculated fill that should be in place prior to concluding gravel packing operations.
The Application of the Repeat Formation Tester to the Analysis of Naturally Fractured Reservoirs
Authors: Stewart George , Wittmann Manfred J. , van Golf-Racht Theodor
Published: December 2007

The RFT* has important applications in the study of naturally fractured reservoirs in which low permeability matrix blocks are contained within a system of connected fractures of high permeability. The pressure inside an individual matrix block, which is observable with the RFT, is determined by the boundary pressure in the fractures delineating the block. Hence RFT data plotted on a pressure-depth diagram follow gradients corresponding to the fluids in the fracture system with changes in slope at the gas-oil and oil-water contacts. In an unproduced reservoir the actual OGOC and OOWC in the fracture system may be determined whereas logs measuring fluid saturations in the blocks indicate quite different distributions because of capillary pressure effects. RFT data from new wells in a developed reservoir allow monitoring of the movement of the GOC and OWC in the fracture network as a secondary gas cap forms and aquifer influx occurs.

Oil recovery from a fractured reservoir is controlled by the permeability of the fracture system and by the permeability and size of the blocks. Fracture permeability is readily available from the analysis of well pressure transient tests but the matrix properties are more difficult to determine. The test pressure response of the RFT, with the probe set in a block, is affected both by the matrix permeability and the block size and a simplified model of the process based on a spherical matrix block with a constant pressure outer boundary and a central point sink has been developed. It can be demonstrated that with a pressure gauge of 1 psi resolution matrix permeabilities of less than 5 md and block sizes of less than 2 m can be detected. The theory has been used to evaluate RFT tests in a fractured reservoir and good agreement between the estimate of block size using this technique and that obtained from a statistical analysis of core was found.

A finite-element numerical model has also been used to simulate pretest buildups in cubic and parallelepiped matrix blocks. The late-time deviation from linear spherical buildup commences when the nearest constant pressure boundary is encountered. Dimensionless buildup type curves for such matrix blocks are given.

The question of supercharging of the block pressure as a result of mud filtrate invasion has also been considered. The proximity of constant pressure fractures limits the degree of over-pressure which can develop at the sand-face. Supercharging only becomes a serious problem at very low matrix permeabilities and the RFT gives successful pressure measurements in fractured reservoirs with a tight matrix.
Pressure Buildup Analysis in a Naturally Fractured Shale Reservoir
Authors: Laudeman Scott K. , Ershaghi Iraj
Published: December 2007

This paper presents case studies of pressure buildup analyses in certain oilfields in California producing from the Monterey formation. These miocene formations are thick siliceous and calcareous organic sediments. Production from the Monterey formation dates back to the turn of the century. In recent years additional exploration efforts have resulted in the discovery of new fields in the Monterey formation. Because of the impact that these fields will have on the proved reserves of hydrocarbon in California, improved evaluation techniques are required for these complex lithologies.

A review of conventional evaluation methods followed by a discussion and the importance of pressure transient tests are included here. Several case studies on onshore and offshore fields producing from the Monterey shale are presented.
Managing Produced Water through Total Oil Recovery: An Integrated Innovative Technology
Authors: Plebon M. J. , Saad Marc A. , Valikangas Antti
Published: December 2007

Produced water can become a major operational, environmental and economic concern when oil fields continue to mature. Managing and handling large quantities of produced water efficiently and effectively requires both understanding of the fundamental physical and mechanical characteristics of the water as well as the changes of those characteristics with both time and additional mechanisms.

TORR Canada Inc. (the company) have developed an innovative technology called TORR™ – Total Oil Remediation and Recovery (the technology) that integrates several oil and water separation and recovery principles is presented. The basis of operation of the technology to handle produced water oil separation and recovery characteristics is explained.

The critical produced water fluid characteristics such as oil droplet size distribution, dispersed oil stability and nature of the dispersed oil are presented and discussed. Performance is demonstrated through field data. Oil concentrations in the range of 100 to 300 mg/L have been reduced to well below 20 mg/L with the technology.

The performance of the technology represents a wide operational range of applications and associated economic and environmental benefits. Operators on offshore platforms who need to comply with stringent regulations may achieve the discharge targets with one technology and one stage. Additionally the technology deserves serious consideration to for the application of de-oiling produced water. Operational complexity of more traditional water treatment process trains can be greatly reduced.
Evaluation of Low Permeability Gas Reservoirs Utilizing Closed Chamber Drillstem Test Techniques
Authors: Reid Hugh W.
Published: December 2007

Closed chamber drillstem testing was originally developed in the early seventies for reasons of operational safety to test geo-pressured, hydrate-prone, high-deliverability gas zones in the Canadian arctic. This original use of the method has been described by Alexander1,2. Since that time, the method has become adopted for more general use in the Western Canadian plains. The two major reasons for utilizing the method have been to preserve secrecy while testing wildcat wells adjacent to land available for sale and, more recently, to gain precision in testing low-permeability low-pressure gas sands.

This paper discusses the evaluation of such low permeability gas zones. The use of graphs of surface pressure versus time (cartesian and log/log co-ordinates) form an integral part of the interpretation process. Certain easily recognizable, well-defined, and abrupt slope changes in surface pressure buildup occur early in the preflow and flow periods. These may be used to qualitatively differentiate between low rate gas and liquid entry. The causes of these phenomena are explained and field examples are provided for illustration. The gas rates are verified independently by simple manipulation of the Equation for Corresponding States. Field examples with extremely low flow rates verified in this manner are presented. The overall configuration of the surface pressure buildup in the cartesian plots may also be utilized to distinguish between truly impermeable zones and those which have suffered severe damage and exhibit "cleanup" (changing skin factor). This may be accomplished even where the rates would be too small to measure in a conventional DST and where the entire surface pressure change throughout the flow period may be no more than 2 or 3 psi. Consequently, zones may be selected which will respond more favourably to stimulation even though calculation of skin damage using conventional Horner analysis or type curve matching may not be possible owing to insufficient shutin time.

A further application is the estimation of down-hole shutin time necessary to reach stable shutin pressure (utilizing the rates of surface pressure change during flow).
Data Acquisition in Pumping Wells
Authors: Cimic Miljenko , Soares Laura
Published: December 2007

Calculating of bottomhole flowing and shut-in pressures and bottomhole flowing rates, based on fluid level measurements and casing head pressures was combined with a convolution method of the build-up interpretation, for vertical and horizontal wells. The downhole pressures and rates were calculated using a mechanistic model(7), which shows good accuracy after comparing with downhole gauges measured data. The main uncertainty still remains the accuracy of fluid level measurement and water content in the annulus fluid, especially during well clean up period, which influences the density of the casing fluid column.

During the shut-in period, conventional pressure build-up analysis (Horner and derivative) and convolution methods were compared with the purpose of showing the advantages of the convolution method over the conventional. Consequently, the well test can be more rigorously interpreted by using convolution rate analysis, and the shut-in time is reduced by three folds, leading to economic advantage of testing costs saving.

The real time knowledge of bottomhole pressure and rates can be used to adjust the optimum downhole pump working regime, avoiding two phase flow through downhole pump and to perform conventional and convolution methods of interpretation without deploying bottomhole gauges. Majority of "brown fields" are equipped with different kind of artificial lift system including positive and dynamic displacement pumps. A fluid level measurement combined with a convolution method leads to an improvement of the production and operating economics of different types of artificial lift systems (SR, ESP, PCP, etc.) and can be used, as well, as a reservoir management tool. This paper includes actual field examples, with solutions that can be applied in the completion and testing of pumping wells. A field experience and subsequent achievement with downhole pumps testing in low permeability oil reservoirs are presented in this paper.
A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming
Authors: Brown Charles A. , Erbe Charles B. , Crafton James W.
Published: December 2007

Natural gas is currently being developed and produced in the Hay Reservoir Area from deep, high pressure, low permeability reservoirs. The reservoirs are predominantly offshore sand deposits which have been significantly altered since deposition. As a result, the reservoirs are difficult to interpret from logs, require stimulation to provide commercial flow rates, and necessitate more sophisticated evaluation methods than conventional reservoirs.

Traditional reservoir engineering approaches are discussed and found to be inadequate in the evaluation of these low permeability sandstone reservoirs based on early life performance. A method of reservoir study is developed by integrating methods from several technical disciplines including geologic reservoir modeling, petrography/reservoir quality analyses, log interpretation modeling, and ultimately, reservoir simulation to rigorously evaluate individual well deliverabilities and reserves. Results show that significantly more gas is economically recoverable than traditional methods of analysis would indicate.
Designing a Produced Water Re-Injection Program in Bekapai Field
Authors: Singh Kalwant
Published: December 2007

Production of oil & gas has very big influence to mankind civilization but the excessive generation of produced water in mature fields as a by-product may have bad impact to environment. Pollution of surface water supplies or fresh water aquifers has become a serious concern in recent years. It is therefore an obligation upon the industry to handle the produced water and disposed it responsibly. This concern has focused attention on produced water re-injection into underground formation as a promising method to discharge oilfield water without polluting potable water supplies.

As refer to regulatory guidelines, injection well for produced water disposal must be operated so that the pressure during injection does not initiate new fractures or propagate existing fractures in the confining zone adjacent to the sources of drinking water, which could damage the receiving layer or cap rock. In order to achieve that purpose, the paper describes planning on operational aspects regarding daily activity/practical operation, which are essential to the successful of water injection project by using developed software. Operational aspect especially includes working pressure along the injection system, estimated formation fluid pressure as function of cumulative injected water, estimated fracture pressure and its relation to proposed injection rate. Operational window for injection must be developed to determine the range of allowable injection pressure and its relationship with the proposed injection rate.

The paper also describe a method to determine the life time of each proposed injection well which is the compilation from the result of operational design analysis and reservoir pressure builds up data from simulation results. This study is very useful to make injection programs and scenarios to extent the injection lifetime (e.g. scenario to add new injector wells).
Construction of the Hondo Field Pipelines by the Reverse J-Tube Procedure
Authors: Matthews Jamie F. , Cunningham Gerald R. , Hofferber John E.
Published: December 2007

During the summer of 1980 three pipelines were constructed between the Hondo Platform, located in 835 feet of water, and the Hondo SALM, located approximately 1-1/2 miles away in 500 feet of water. Figure 1 shows the Hondo Platform, SALM, Offshore Storage and Treating (O.S.&T.) vessel, and pipelines. These pipelines, ranging from 6-inch to 12-inch in diameter, were installed by the reverse J-tube procedure, a technique developed by Exxon especially for construction of deepwater pipeline systems. The technique may also be cost effective in certain shallow water applications.
Pipe Flow Rheometry: Rheological Analysis of A Turbulent Flow System Used for Cement Placement
Authors: Bannister C. E. , Benge O. G.
Published: December 2007

Determination of the Theological behavior of cement slurries is essential for proper evaluation of flow rates required to achieve optimum mud removal. Rhe-ological characteristics of cement slurries and spacer fluids have been evaluated using pipe-flow rheometry. By this method, rheological measurements were obtained by monitoring the pressure required to pump a fluid through either a pipe or an annular gap.

The results suggest that the rheological properties of cement slurries are modified by apparent "slip" at the pipe surface making the onset of turbulence more difficult to achieve. This wall "slip" is attributed to particle migration away from the pipe surface when the fluid is sheared. Due to this anomalous behavior, a three-parameter mathematical model is required to evaluate pump rates required for the onset of turbulence.

Use of pipe-flow rheometry has resulted in the design of a turbulent flow fluid which is "rheology-con-trolled" to permit easy calculation of the critical pump rate. The value of turbulent flow in cement placement is demonstrated by field evaluation of several wells in which production liners and intermediate casings have been successfully cemented into place using a "rheology-controlled" spacer fluid ahead of the cement slurry. To insure "rheology-controlled" behavior, the spacer fluid exhibits excellent fluid-loss control to inhibit rheological changes detrimental to good mud removal.

Pipe-flow rheometry has been instrumental in characterizing the factors responsible for turbulent flow behavior. Proper rheological evaluation coupled with fluid-loss control behavior will give the necessary information for optimizing cement placement.
Cleanup of Water-Based Kill-Pills in Laboratory-Simulated Perforation Tunnels During Flowback
Authors: Suri A. , Sharma M. M.
Published: December 2007

Kill-pills and completion fluids form internal and external filter cakes in perforation tunnels. A laboratory study on the cleanup of water-based kill-pills in lab-simulated perforation tunnels is presented. Flow initiation pressures (FIP) and return permeabilities are measured at constant pressure during flowback.

A sized calcium carbonate kill-pill and a bentonite mud are tested on rocks ranging in permeability from 25 md to 1500 md with various lab-simulated perforation tunnel dimensions. Both single-phase and two-phase experiments are conducted to better understand the factors affecting the cleanup of the perforation tunnels.

The FIP values are found to range from 2 to 15 psi depending upon the perforation tunnel dimensions. The FIP values are small (< 4 psi) in large diameter perforations and the external filter cake is formed only along the walls of the tunnel. These small FIP values in large diameter perforations are comparable to the FIP values obtained for open-hole completions with no perforations. However, in small diameter perforations, large FIP values are obtained, and the external filter cake is found to completely plug the tunnels. Both internal and external filter cakes determine the FIP in perforations with small diameter; however, the FIP in large diameter perforations is mostly determined by the internal filter cake. Pressure gradients up to 20 psi / inch and flowback rates up to 0.3 bbl/day/perforation are found to result in approximate skin factors < 2 for all simulated perforations which had an overbalance of 100 psi.
Simplified Method for Characterizing Fractured Carbonate Media
Authors: Pérez-Rosales C. , Luna E. , Serrano E.
Published: December 2007

Quantitative characterization of fractured carbonate rocks is of interest for several reasons: first, because naturally fractured carbonate oil reservoirs are among the most important in the world; second, because fluid flow through the pore system depends on the internal geometry of the rock; and, third, because numerical simulation of such reservoirs require reliable values of matrix porosity, fracture porosity, and block size.

Naturally fractured reservoirs are complex systems whose flow properties are not well understood. From the fluid transport viewpoint, fractured carbonate reservoirs can be considered to consist of two basic components: matrix blocks and fracture network. Matrix blocks are characterized by their low fluid conductivity, and their main function is to storage fluids, whereas the fracture network is composed of highly conducting channels.

This paper describes a simplified method for determining matrix and fracture porosities of carbonate media, as well as block size. The method makes use of total interconnected porosity and formation resistivity factor data. Of fundamental importance to the method is the fact that, in the case of fractured carbonate media saturated with a conducting fluid, the conductivity of the fracture network is much greater than that of the matrix blocks, so that, for practical purposes, the latter can be considered as negligible.

For illustration purposes, an application to a real case is presented. To this end, use is made of two procedures, one for fracture porosity and the other for block size. A step by step description is given for each procedure. It is considered that the simplicity of the procedures make the methodology an attractive tool for the characterization of carbonate fractured reservoirs.