bluuebunny/crossref_metadata_2025 huggingface dataset:
Solid Expandable Tubulars Provide Substantial Value to Existing Wells
Authors: Rivenbark Mark
Published: December 2007

Major operators are using solid expandable tubulars in existing wells to tap added reservoir pay. This use of the technology is the result of close collaboration between the contractor and the operator, particularly the reservoir engineering and drilling departments. Together they have devised plans that maximize the return-on-investment (ROI) and the long term sustainability of the reservoir.

The use of solid expandable tubulars to provide a larger drainhole in existing wellbores is proving to be a considerable benefit to many operators. Aside from the obvious production gains from a larger borehole, the operator also gains on the drilling side of the equation. The larger inside diameter (ID) through the solid expandable casing allows for the use of larger drilling tools. These larger tools typically drill farther and faster than smaller tools and suffer far less non-productive time due to failures.

This paper reviews the value derived from using solid expandable tubulars in the casing design of existing wells with actual case history data. Further, the paper details ancillary benefits that can be factored into the value gained by the operator.
LWD Formation Pressure Testing Allows Decision Making While Drilling
Authors: Hahne Ulrich , Kaniappan Aravindh , Pragt Jos , Buysch Arno
Published: December 2007

The potential operator cost efficiencies of acquiring valid formation pressure data while drilling are becoming more influential in deciding the value proposition of a wireline reservoir characterization program. Cost efficiencies may indeed be pivotal but importantly, the benefit of acquiring pressure data in real time needs equal consideration, as a number of novel applications now exist.

The paper will use case histories and lessons learned from experience with 300 logging while drilling (LWD) formation pressure runs in different operating areas including Asia Pacific to demonstrate the applicability to conventional formation pressure applications, traditionally acquired with wireline formation testers upon reaching section or well total depth (TD). These are the determination of formation pressure, fluid contacts, reservoir connectivity, and near-wellbore mobility. We discuss novel real-time applications and benefits for drilling and subsurface teams, such as mud weight management, safe selection of casing points, calibration of pore pressure predictions, selection of wireline sampling points, reservoir monitoring, geosteering, and obtaining data in high-risk wells.

Incorporating formation pressure testing into the drilling process presents challenges to perform measurements in a timely manner, as well as the need for continuous circulation while testing to ensure wellbore safety.

Providing this type of while-drilling formation evaluation data with an LWD tool allows a continuous approach to data evaluation and decision-making. The ability to measure accurate LWD formation pressure data in a variety of hole sizes represents a significant opportunity for safe and cost-efficient wellbore construction, especially in challenging environments.
Drilling Fluid Additives and Engineering to Improve Formation Integrity
Authors: Goud M. C. , Joseph Givi
Published: December 2007

Fracture propagation is a very commonly seen phenomenon when using synthetic-based drilling fluids (SBM) in areas of narrow drilling windows. Consequently, deepwater drilling has brought lost circulation control to a more critical level. This is further compounded by other deepwater drilling-related problems such as narrow pore pressure/fracture gradient windows, cold drilling fluid temperatures, high equivalent circulating densities (ECD's), high cost per barrel and a higher cost for lost rig time/non productive time.

Induced fractures pose an even more complicated problem due to the various factors involved. These fractures can be influenced by to the nature of formation, drilling and/or by mechanical effects. One condition of paramount importance in sealing induced fractures is having the lost circulation material (LCM) effectively isolate the tip of fracture.

In its deepwater operations, Reliance introduced the use of crystalline graphite in conjunction with sized calcium carbonate into the SBM to strengthen the formation. Graphite is utilized to seal and isolate the near wellbore fractures the tip along with optimizing the rheology of the SBM. The particle size selection of the bridging particles was engineered based on software to optimize the bridging and sealing effect, which employed knowledge of the pore throat sizes and the permeability of targeted formations. This has resulted in elevating the formation integrity test pressure (FIT) and helping drill longer sections, which in normal circumstances would have been a difficult task.

The authors will discuss the design of these drilling fluid additives and their impact. Also outlined are the treatment techniques necessary to ensure minimal formation of induced fractures along with the engineering tips required to ensure successful application of such treatments. The authors will also review the results of actual formation strengthening seen in one of their exploration wells.
Effect of Pressure in a Well With a Vertical Fracture With Variable Conductivity and Skin Fracture
Authors: Gonzalez-Chavez Miguel Alejandro , Cinco-Ley Heber
Published: December 2007

A mathematical model was developed to study the behavior of a well with variable finite-conductivity and skin fracture, for a vertical fracture in an infinite slab reservoir.

The solution is valid for slightly compressible fluid and gas fluid applying the pseudo-pressure concept. The constant rate with wellbore storage and constant pressure are the production modes considered. Curves type are used to showsthe effect of the changes of conductivity and skin near the well and in the extreme of the fracture. A field test was analyzed to detect the changes of the properties. This model is a tool to analyze real cases when the fracture properties are affected during the productive life of the well.
Thermal Simulation and Economic Evaluation of Heavy-Oil Projects
Authors: Rangel-German E. R. , Camacho-Romero S. , Neri-Flores U. , Theokritoff W.
Published: December 2007

Many recent hydrocarbon discoveries in the Gulf of Mexico are heavy and extra-heavy oils. Additionally, given the imminent decline of lighter crude oil fields such as Cantarell (the primary Mexican oil field), it seems that most of the crude oil production in Mexico, in the midterm, will come from heavy-oil reservoirs. The need to analyze the feasibility of unconventional recovery methods becomes readily clear. This paper presents a methodology to evaluate heavy-oil projects using thermal simulation and economic evaluation.

Thermal recovery methods are used to exploit heavy oil reservoirs, where oil viscosity is very high and mobility low at the reservoir temperature. It is desirable to reduce the oil viscosity by increasing its temperature. An affordable and easy-to-implement technique is by means of heaters or an electric cable.

This paper presents the results of this methodology, which includes thermal compositional simulation of a synthetic grid model, with the fluid properties mimicking those of heavy oils recently discovered in the marine region of the Gulf of Mexico.

PVT analysis, viscosity curves, rock properties, relative permeabilities, capillary pressure, and reservoir pressure and temperature are also studied.

The economic analysis was performed using current capital expenditures for drilling and completion and operating and maintenance costs. Different scenarios for costs, oil and gas prices and capital investment were studied. A sensitivity analysis was performed to determine the variables having the highest impact on the economic value of the project.1

This methodology showed that introducing heat by means of an electric cable is a technically viable and profitable alternative, even for projects under off-shore economic premises, which are considerably higher than those for onshore projects. Implementing the heating from the beginning of the project and continuing to its completion, was found to be the most important factor for the economic success of this method.
HP/HT Cement System Design—East Coast Case History
Authors: Haidher Syed , Kale Samir , Affes Sami , Nair Suresh Kumar
Published: December 2007

Cement Systems require conformance of specific parameters for the longevity of the system placed as a sheath. Challenges of the system design are exacerbated considering the environment for placement of the sheath. HPHT cement systems require special design attention, and the authors propose to share one such case history in designing of the HPHT system for Eastern India Offshore.

HPHT cement systems require not only modified testing procedures, but products also. HPHT cement system products are required to withstand BHST temperatures for the life of the well without considerably altering the slurry system properties. Modified test procedures and products requirements for slurry system bring additional logistical challenges like preparation and availability of right cement blend for testing and preparing the slurry system for the application.

Considering the temperature gradient of 2.23°F/100ft, bottom hole static temperature (BHST) for the 7" liner job was 467°F. The mud weight for the section was planned between 14-16 ppg (1.67 to 1.9 sg). Computed BHCT alone was considered inadequate and determination of the hot spot in the wellbore was required. Computerized simulator was used for the purpose. Results show that the hot spot temperature predicted by the simulator was higher than the computed BHCT and the depth of the hot spot was shallower than TVD as normally anticipated. The simulator runs are recommended for determination of hot spot for HPHT testing of cement systems in particular. The simulator considers effects of various fluids pumped and their contact times along with the heat capacities during the application.

Product choice for preparation of the Cement systems used earlier for the high temperatures encountered in Western India offshore were reviewed and preliminary testing was carried out on the basis of the prognosed temperature. However predictions from the temperature simulator yielded higher temperatures for the East coast well. This required a different product set for the cement system design.

The authors feel that the review of this case history and the design challenges at this technology meet shall potentially benefit the design engineers in understanding and enhancing their knowledge about design practices for HPHT cement systems.
Expandable and Contractable Bit
Authors: Agarwal Sharad Ashok
Published: December 2007

EC bit is an expandable and contractable bit a new concept of drilling the boreholes of different radii at different depths and in zone of our choice without changing the size of bit and without tripping operations.

During conventional drilling boreholes of different radii at respective depths are being drilled. In order to drill boreholes of different radii bits of different sizes are manufactured which consumes tremendous amount of material, time and finally the cost. In order to face this challenge here a tool has been proposed which uses single comprehensive bit size to drill complete well. The mechanism of this tool is based on the concept of rack and pinion system. The rotation of gears (pinions) and movement of the racks will help us to drill the borehole of radii of our choice.

With the help of this tool the important advantage is that the drillstring is not changed every time, only one size of drillstring is being used to drill complete well. This revolutionary idea of manufacturing ONLY ONE BIT SIZE will cost the drilling contractor a tremendous reduction in costs of bits. The other advantages include enhance production, reduction in skin damage and control the problem of sand production.
Benchmarking the Cycle Speed of an AC-SCR Drilling Rig with Special Reference to Upper Assam Operation
Authors: Gogoi G. , Hussain A.
Published: December 2007

Benchmarking can be done for the various processes involved during rig up, rig down and drilling operation of an AC-SCR (E-1400) land drilling rig operated in Upper Assam Development Oil Field for productivity enhancement. An endeavor was made in OIL INDIA LTD to benchmark the drilling cycle time for all AC-SCR (E-1400) land rigs by reducing the Non Commercial Time and hence to increase the Cycle Speed.

In this benchmarking, three main areas of a Drilling Cycle were considered.

Benchmarking the rig down/rig move and rig up operation of an AC SCR (E-1400) drilling rig. This area is a major contributor for the Non-Commercial Time of a Drilling Cycle, which is by average, is about 30% of the Total Cycle. Benchmarking the commercial time (i.e. when the rig is busy in making the hole including the trip time). Trip time is a major portion of Non-Commercial Time within the commercial time. This contributes about 20% of the total drilling time. This was done by using intelligent technology and system for drilling performance. Since it is a fully developed field, therefore we have benchmarked the production testing time as 15 days for two ‘sands’. This includes wiper trip, CBL / VDL, changing over & lowering of well fluid level, and finally perforation & observation. By introducing the multi-skill performance technique among the crew. This concept helps to increase the efficiency & effectiveness of the crew deployed in the rig. This in turn helps in reducing break down time.

The natural environmental factors prevailed in upper Assam areas were considered while bench marking the drilling cycle time.

It has been worked out that by implementing the benchmarking of the whole cycle, a rig can complete about 3.47 cycles per year against 2.48 cycles per year before benchmarking.
Economic Pumping Technology for Coalbed Methane (CBM), Stripper Oil, and Shallow Gas Well Deliquification
Authors: Dickey Michael W.
Published: December 2007

Operators of shallow, low flow oil and gas wells have commonly relied on conventional beam pump and other artificial lift methods to produce these types of wells. Often, the use of these pumping systems results in inefficiencies, short run-life and environmental challenges that affect the overall economics of the operation.

A hybrid artificial lift system has been developed to allow operators of shallow, low flow oil and gas wells the opportunity to produce the wells in a much more economical fashion than beam lift or other conventional methods. This paper introduces the technical aspects of the system, its operation and deployment techniques, and the power savings it realizes in comparison to beam lift and other traditional lift systems.

The Hydraulic Diaphragm Electric Submersible Pump (HDESP) uses a technology that offers a number of benefits to operators. The system's hybrid design advantageously combines the beneficial features of both electric submersible pumps (ESP) and hydraulic diaphragm pumps (HDP). Both of these types of systems are widely accepted in their respective industries.

Laboratory tests and deployment of the HDESP in producing wells confirm the systems capabilities in vertical wells up to 2500 feet in depth with production rates less than 200 BFPD. Ongoing design engineering has objectives of greater depths and higher volumes. Heat issues commonly associated with electric submersible motors are also being addressed.

Abrasives and gas handling comparisons are made between ESPs and beam pumps. Procedures optimizing HDESP reliability within adverse wellbores are also described.

Power cost studies indicate that the HDESP can reduce electrical cost by as much as 50% compared to beam pumps and water-well type ESPs. The net positive suction head (NPSH) requirement is considerably less, allowing an operator to drawdown fluid levels very close to the pump intake. This offers potentially significant production benefits to the producer.

At the conclusion of the paper, readers will have a thorough understanding of the function of the HDESP system, its performance successes and failures, suitable target applications, deployment techniques, and the overall potential for economic benefit the system brings.
Obtaining Permeability Values in a Coalbed Methane Core-Hole Utilizing Slimhole Technology Coupled With an Injection/Falloff Technique
Authors: Rodvelt G. , Toothman R. , Hayhurst J. , Oestreich R.
Published: December 2007

It has been a common practice in the industry to obtain core samples to determine gas content for coalbed methane (CBM) projects; however, due to economic issues, permeability testing has usually been avoided. To obtain core samples, the core hole is drilled, samples are collected, and the core hole is plugged per state regulations. Obtaining permeability test results in an openhole core hole on the other hand is time consuming and does not provide consistent results. However, if permeability testing initially could be completed in the core hole, not only could time and money be saved, but permeability data, core data, and logging information could all be tied together from the same wellbore. An informed decision could then be made based on this additional information to help determine whether to move forward with the project or move to another area.

The authors present a process that includes drilling a 3 1/2-in. core hole, collecting a 3-in. core, cementing 2 7/8-in. tubing, and conducting permeability testing using an injection/falloff technique. A unique cement blend is presented that reduces cement loss to the cleat system while providing a lightweight blend with "zero" free water and low friction pressures for placement. A test assembly consisting of slimhole packer, downhole shut-in device, and downhole pressure gauges is run in the hole on 1 1/2-in. tubing to provide isolation, eliminate wellbore storage, and record bottomhole pressure and temperature. A self-contained permeability test trailer capable of pumping and recording rates as low as 0.03 gal/min is essential to this process. The objective of the test is to inject fluid at matrix rates without fracturing the coal seam, then analyze the data using conventional well testing software and a CBM reservoir simulator to arrive at permeability and reservoir pressure. Production forecasting can then be simulated for project review.
Reservoir Knowledge and Drilling—Benefits Comparison for Underbalanced and Managed Pressure Drilling Operations
Authors: Finley Doug , Shayegi Sara , Ansah Joe , Gil Isabel
Published: December 2007

The industry is now becoming more knowledgeable concerning underbalanced drilling (UBD) and managed pressure drilling (MPD). These techniques are gaining popularity because of their capability to control severe fluid losses and other problems that are inherent to conventional overbalanced drilling. As a result, considerable increase in their usage has been noted; however, with these increases, it has become apparent that there is a great deal of confusion concerning the basic concepts of each technique and when each should be used. Generally speaking, UBD can be described as a reservoir performance improvement and characterization tool that also provides drilling benefits. Another advantage is that UBD can offer a unique well testing environment in which the properties of reservoir layers can be determined while drilling. MPD, on the other hand, primarily addresses drilling-related problems that result in nonproductive time (NPT) in drilling scenarios. Sometimes, however, there are well scenarios in which both techniques might be needed in different hole sections.

Reservoir information gained during underbalanced drilling also can help reduce the time and cost associated with gathering and analyzing well-test data post-completion with conventional methods. Techniques have been developed to quantify reservoir properties and characteristics for homogenous and heterogeneous and/or fractured reservoir systems.

This paper focuses on where each concept should be used and what benefits can be expected from their application. Results from UBD and MPD case histories are used to quantify the results from these operations. Differences between the two techniques concerning equipment requirements and reservoir characterization potential are also analyzed.
New Wells and New Challenges: Selecting the Most Appropriate Drilling and Drilling Fluid Practices
Authors: Pratap K. Krishna , ThyagaRaju B. A. , Kali A. T.
Published: December 2007

The development of giant oil field "Mumbai High" has been a learning platform for the role that drilling fluids play in the successful rejuvenation program of any oil field. This paper attempts to manifest the learning curve right from the low angle wells drilled using simple conventional systems limiting the role of fluid services to the basic functions of enabling the normal drilling process. Over the years when farther parts of reservoir were explored at higher angles, the crucial role of the inhibition, bore hole stress management were exposed. The ultimate challenge was posed by the horizontal program where in the grey areas of cutting bed formation, hole cleaning, imperative drilling and drilling fluid practices dictated the completion of any well. The final Phase of the ERD program showed the critical aspect of minimization of pore pressure transmission and gauge of hole to the successful drilling of any well. The chronology has dictated the imperative selection of the right drilling fluid for each phase starting from the change over to the non-dispersed KCL-PHPA systems the Cloud point Glycol system via the most inhibitive Silicate system and culminating with the selection of Synthetic Oil Base Mud for the long horizontal wells. The redevelopment program indicated that there are no degrees of freedom as far as the inhibition, hole cleaning, bore hole stress management and drilling practices are concerned, and that is up to the drilling fluid chemist to play a proactive role to fill in the grey areas between the driller, G&G and the drilling fluids.
Overcoming the Challenges of Building 3D Stochastic Reservoir Models Using Conceptual Geological Models—A Case Study
Authors: Al-Khalifa Mohammad A. , Payenberg Tobias H. D. , Lang Simon C.
Published: December 2007

Construction of reliable 3-D geological models for reservoir simulation requires a detailed understanding of facies distribution and connectivity within the interval of interest. In particular, it relies on lateral and vertical variabilities in reservoir quality within and between different flow units. Despite thorough data integration and interpretation, several challenges were encountered while integrating geological knowledge into a 3-D stochastic geological model.

Some unconventional approaches had to be taken in order to best reflect the geological understanding of the reservoirs while using commercially available software. For example, the 3-D stochastic facies modelling of the reservoir units was based on conceptual geological models. Models were constructed for each reservoir zone through the analysis and integration of core and log data from 50 wells in the study area. However, it was seen that utilising either object modelling or pixel-based modelling methods alone would not generate stochastic models that adequately honoured the conceptual geological model. Consequently, the two modelling methods were used together to generate combined models.

A further challenge was to determine adequate facies proportions for each reservoir zone. The direct use of facies statistics from well logs in stochastic modeling lead to unrealistic facies distributions. To overcome this, dummy wells were added to make facies proportions matches the conceptual models rather than basing it on the existing wireline logs alone.

Taking these unconventional approaches lead to a greater accuracy of reservoir and porosity distribution around the reservoir. Moreover, the methodology used in this study provides new ideas that can be used in modeling other fields with fluvial depositional settings.
Revitalizing the Richard King Field: Using New Technology in a Cost-Effective Manner on Mature Fields
Authors: Swanson Jeff , Stevens Greg , Hall Rod
Published: December 2007

What else can be done to an old field where past operators have tried just about everything including 3-D seismic? If there is anything else, would it add quantifiable value to the property?

As an acquirer of mature properties, this common challenge for Durango Resources Corp. ("Durango") was dealt with by combining old-fashioned geological and engineering methods with new technology. Some of these methods included thorough data gathering and detailed analysis of the stratigraphy and depositional environment of all well logs.

Completing a detailed field study combined with new technology has resulted in new life for the old field and has added definable value to the property.
Granite Wash Field Study—Buffalo Wallow Field, Texas Panhandle
Authors: Ingram Stephen , Paterniti Isaac , Rothkopf Brian , Stevenson Chris
Published: December 2007

One of the major producing zones in the Texas panhandle is the Granite Wash. The Granite Wash play is currently focused on Wheeler and Hemphill counties on the Oklahoma border and covers more than 1,000 sq mi of tight-sand formations. The focus is less on discovery and more on cost reduction in drilling and stimulating wells. The Texas Railroad Commission in some cases has lowered spacing to 40 or 20 acres per well, which, along with steadily high gas prices, form the basis of the high rig count working in the region.

Because of the lack of concise and consistent nomenclature in the Granite Wash plays of the Anadarko Basin, this case study addresses the stimulation trends the industry is using in the Wash play. The target area of this study consists of three counties located in the Texas Panhandle: Wheeler, Hemphill, and Roberts, with extensive data only within the Buffalo Wallow Field. This paper discusses the reservoir development and characteristics, current and former completion techniques, and production comparisons. The goal for this study is to determine best practices for completion procedures in the Granite Wash.

Previous satabases1 have been expanded using detail data on fracture treatments performed and production recorded from 135 wells over the given period from 2002 through early 2006. The operator and service provider are currently analyzing the data. The goals of this analysis are to (1) define basic criteria (rules of thumb)2 for optimizing the potential for the highest initial production and 90-day cumulative production, and (2) discover correlations, if any exist. The data of interest reside in each well's specific fracture treatment data that includes the following, but is not limited to treatment rate, proppant volume, treating fluid volume, gross pay interval, net pay interval, proppant mesh size, and treating pressure.

One example of the correlations obtained is: based only on rate, if the treatment is pumped at a minimum of 100 bbl/min, a good well will be achieved 66.7% of the time versus 55.2% when the treatment is pumped below 100 bbl/min. When the production criterion is 60-day cumulative production, the gap lessens: 65.6% when the treatment rate is over 100 bbl/min; 60.7% when the treatment rate is less then 100 bbl/min. Many other correlations regarding perforated interval, treatment volume, proppant mass, proppant sieve size, etc. are presented in this paper.
New Methods and Equipment for Dewatering Unconventional Gas Resources Using Sucker-Rod Pumping Equipment
Authors: Mahoney Mark W. , DeWerff Randy
Published: December 2007

Dewatering coalbed methane and low-pressure gas wells has been a challenge for oil and gas producers. When compared to ESP and PC pumping, sucker rod pumping is a very forgiving method and wells can be pumped to very low pump intake pressure without damaging the pumping equipment. This has generated a strong interest in using sucker rod pumping in dewatering gas wells. Quite often operators try to use sucker rod pumps and rod pump system designs that are the same types used for pumping single phase (liquid) fluids and they do not achieve the desired fluid removal and are not designed to handle sand, coal fines and other solids encountered in this type of production. New designs in sucker rod-pumping equipment and rod-pumping systems for high GLR, coal fines and solids have greatly changed the approach to dewatering unconventional gas resources. This paper will examine the new equipment and design criteria being used to help dewater gas wells.
Successful Application of Relative-Permeability Modifiers To Control Water Production in Rose Run Fracturing
Authors: Fry Len , Everett Don , Moody Mark , Hina Brad , Gessel Jim , Gessel Steve
Published: December 2007

A number of wells in the Rose Run formation of Ohio were all completed with small acid treatments and placed online within the last 12 years. These wells are approximately 20 miles west of Canton, near Brewster.

Reductions in well performance over short periods of time indicated the need to stimulate the wells. Fracture stimulation has not been widely used in the area due to the potential water production resulting from fracturing out of zone. The objective of the hydraulic fracturing treatments in these wells was to obtain a short, highly conductive propped fracture past the damaged area. Fracturing models were used to determine the fracture geometry.

In an attempt to minimize post-fracturing water production, a relative permeability modifier (RPM) was pumped as a preflush to the fracturing treatment. Fracture designs were based on individual well characteristics. The RPM was designed to effectively reduce the relative permeability to water without significant changes to the hydrocarbon relative permeability. A low gel-loading borate crosslinked fluid was then used to fracture-treat the wells.

A total of 12 wells were fractured with the RPM ahead of the fracturing treatment. The results of these treatments were compared to offset wells that were fracture-treated without the RPM. The increase in water production in the RPM-treated wells was one-half that of the offset wells. These RPM-treated wells also had lower water-oil ratios (WOR) and water-gas ratios (WGR).

This paper will describe the properties of the RPM, the Rose Run formation, as well as, the treatment designs. It will also detail the post-fracturing results and the comparisons with the offset wells.
Slickwater Technology Helping Greene County Enhance Natural Gas Production
Authors: Mills Robert D.
Published: December 2007

The Appalachian Basin is known for producing wells that have extreme longevity to include wells that are still producing after 30 or more years. The last several years, Greene County in Pennsylvania has become an active area. The producers have been drilling the Upper Devonian sandstone at depths of 2500 to 5000 feet. Various formations including the Bradford, Speechley, Balltown, and Fifth Sand are typical in a completion of the wells. The conventional completion method has been to utilize a cross-linked polymer gel system. A newer approach utilizing slickwater technology being used on some shale formations has been modified for use in Greene County.

The formations commonly average between 4 to 20 feet of net productive reservoir per zone with 6 to 9 percent porosity, and 50 to 80 percent gas saturation. The formations have been difficult to initiate a fracture. Once a fracture has been initiated, transport of proppant into the zones has also been difficult. Screen-outs have been common in stimulating the tight zones.

During the flow-back process of a screened-out zone, probable formation particles were observed accompanying the sand during the latter stages of the flow-back. Analysis of the log and flow-back particles indicated the particles were primarily a siltstone or shaley-sandstone. Potential pay zones that show a siltstone or shaley-sandstone composition were selected and treated with a slickwater pre-pad.

The volume of slickwater has been 20 to 30 percent of the total volume of the treatment. The slickwater treatment is being used to connect the minor fingerlike fractures within the zone that show shale characteristics. It is believed that the slickwater treatment extends the total fracture length while stimulating the formation. The minor fractures are believed to contribute substantially to the production within the tight gas sands of the Devonian sandstone.

A cross-linked polymer gel used to transport proppant follows the slickwater treatment. The fluid used for proppant transport is guar based. The fluid is chemically enhanced while being pumped down the casing to give higher viscosity and proppant transportability. Proppant loading ranges from 0.5 to 3 pounds proppant added.

Early production data is showing an increase in initial well production. The production increases have been sufficient to continue the treatments. The increased initial production helps decrease the time required to see a return on the investment for the producer.
Performance Evaluation of a Reservoir Under EOR Recovery: Intisar ‘D’ Reef, Concession 103, Libya.
Authors: Vilela M. J. , Gharsalla Mohammed , Elghmari Mohamed , Majdoub Abdulhamid
Published: December 2007

The Intisar "D" reservoir is a carbonate reef of Paleocene origin with no appreciable flow barrier. This is an under saturated reservoir with an oil of 40 °API and solution gas oil ratio of 595 SCF/STB. The reservoir, having 452 ft of net pay, is at a datum of 9,000 ftSS with an initial OOIP of 1.76 billion stock tank barrels and initial reservoir pressure of 4,257 psia. A series of very successful reservoir management strategies have been applied in order to optimize and increase the production capacity and reserves. So far 69.2 % (1.2 MMSTB) of OOIP has been recovered mainly due to implementation of an EOR project.

From the commencement of production in 1969 up to 1981, Intisar "D" was under bottom water injection for reservoir pressure maintenance and crestal hydrocarbon gas injection for pressure maintenance, gas conservation and enhanced oil recovery; then water injection was halted, but gas injection has been continued successfully until now. Against common knowledge, oil recovery to gas (immiscible) was more effective than water flooding.

For analysis purposes the reservoir was divided in two portions: Water Swept Zone (WSZ, from the base of the reservoir up to the level of WOC in 1981) and Gas Swept Zone (GSZ, from the level of WOC in 1981 to the top of the reservoir) to separately evaluate the displacement sweep efficiencies. Gas injection at the crest of the reservoir has been an extremely successful drive mechanism, although this process has been immiscible most of the time. To December 2005 cumulative oil production was 1,218 MMSTB, of which 823 MMSTB were driven due to gas injection as secondary and tertiary recovery methods while 395 MMSTB were produced due to waterflooding.

This is one of the biggest EOR processes worldwide.

This paper discusses the strategy used to produce this reservoir and also to compute the produced oil recovery from the different drive mechanism employed.
Trapped Annular Pressure—A Spacer Fluid That Shrinks
Authors: Bloys B. , Gonzalez M. , Hermes R. , Bland R. , Foley R. , Tijerina R. , Davis J. , Cassel T. , Daniel J. , Robinson I. , Billings F. , Eley R.
Published: December 2007

In deepwater or other sub-sea completed wells, fluids, usually spacers or drilling fluid, are commonly trapped in casing annuli above the top-of-cement and below the wellhead. When these trapped fluids are heated by the passage of warm produced oil and gas, thermal expansion can create very high pressures (10,000-12,000 psi or more) and cause the collapse of casing and tubing strings.1,3,11,14

Mitigation methods such as vacuum insulated tubing to limit heat transfer,5,6,13 nitrogen foam spacers to give highly compressible trapped fluids,7,8,9,10 crushable urethane foam insulation,2 etc. are somewhat successful but are either very expensive, logistically troublesome or have unacceptable failure rates. This paper covers a new approach which has created a water-based spacer fluid that will be used just ahead of the cement. The spacer contains perhaps 20-40% of emulsified methyl methacrylate monomer (MMA). Upon polymerization, the MMA phase shrinks by 20%, creating room for the remaining fluid to thermally expand without creating catastrophic pressure. The polymerization is triggered by heat and the target temperature can be controlled by an appropriate type and concentration of chemical initiator. Premature polymerization during spacer placement can be prevented by an appropriate type, and amount, of inhibitor.

A spacer formulation (viscosifier, emulsifiers, MMA, weighting agent, inhibitor, etc.) has been developed which covers the range of densities expected in deepwater wells. A matrix of bench top tests has determined the types and amounts of initiator and inhibitor needed to adjust the temperature of the polymerization to the range of temperatures expected in the field. These results have been confirmed in an advanced pressure-volume-temperature (PVT) cell that closely simulates downhole conditions. A successful mid-scale field trial has been conducted in a 500-ft test well using normal oilfield casing, drillpipe, pumps, etc. A method was devised to add the initiator on-the-fly as the spacer is pumped downhole. Safe handling procedures have been developed for mud plant mixing, transportation, and rigsite application. The new spacer will be tested in an onshore well in the near future, and then in several deepwater wells prior to commercialization.
Porosity Partitioning and Flow Unit Characterization from an Integration of Magnetic-Resonance and Borehole-Image Measurements
Authors: Pal Aditi , Seth Kapil , Guru Udit , Tiwari R. R. , Dasgupta D.
Published: December 2007

The petrophysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However, it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating diagenetic features occurring in micro scale. It becomes imperative to look at both micro and macro scale heterogeneity for evaluation of such reservoirs, which has a direct impact on the production, and water injection scheme of such reservoirs.

The NMR data and image based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro, meso and macro porosity. Borehole image logs have been interpreted in terms of defining the connectivity of the features seen on the image. This is then used to define a high-resolution connectivity index. An integrated approach using the NMR and the image is being proposed to identify such high permeability streaks that can explain the production performance or the water injection behavior at a later stage of development of the field. Based on the porosity partitioning technique an improved permeability estimate is made. The production results confirm the findings of this study.
Reserves Estimation and Classification Challenges in a Mature Oil Field
Authors: Zubari Hisham K. , Kumar K.
Published: December 2007

Estimation of hydrocarbon reserves is governed by natural, technological and economic factors. Re-estimations and reviews continue almost till the end of exploitation in many instances. Estimation of oil reserves, when a field is in its initial stages of development is a relatively easy task. The estimation will not invite critical or close scrutiny, as the oil production at that stage is far lower than the reserves calculated. However as the field matures and the cumulative oil production approaches the estimated value of reserves, the accuracy in the estimation of reserves becomes crucial and more important. Also the estimation process itself is a challenging task, in the light of uncovering geological complexities and reservoir dynamics during the development and the exploitation methods employed to produce the oil.

Bahrain field, the first discovery in the Arabian Gulf region, has been on production since 1933. It is a multi-stacked field with 16 oil and 4 gas reservoirs. Most of them are carbonate reservoirs. The nature of the fluids varies from tarry oil in the Aruma formation occurring at shallow depths to dry gas in the deep Khuff zones.

The geology of the field is complex with a large number of faults on the structure. The major oil zone Mauddud – an oil wet system - has been on gas injection from 1938. The gas injection has lead to the transfer of oil and gas into layers above and below through the faults. Though many reservoirs of the field have reached mature stage, there are some zones containing oil resources still unexploited due to the heterogeneities, complex nature of the fluid distribution, unfavorable rock-fluid characteristics, compartmentalization, thin oil rim overlain by gas and underlain by water, etc.

This paper brings out the challenges posed by the above situations while attempting to estimate and classify oil reserves.
Lessons Learned from Energy Models: Iraq's South Rumaila Case Study
Authors: Kabir C. S. , Al-Khayat N. I. , Choudhary M. K.
Published: December 2007

Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy.

We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is about 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations.

Lessons learned from this study is that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models.
Fully Upscaled Saturation-Height Functions for Reservoir Modeling Based on Thomeerg's Method for Analyzing Capillary Pressure Measurements
Authors: Buiting J. J. M.
Published: December 2007

Upscaling is a long standing problem for the construction of saturation height models. Upscaling is difficult when desiring to honor and retain the information obtained from core descriptions, facies classifications and mercury injection capillary pressure (MICP) data. In Saudi Aramco MICP experiments are widely used for measuring the architecture of the rock's pore system. For the analysis of these measurements Thomeer functions are standardly used. The Thomeer parameterization proved to be very adept for handling the complexity and multimodality of carbonate pore systems. In this paper a direct and closed form solution of the upscaling problem of MICP data to arbitrary large reservoir elements has been derived for standard Thomeer functions. All statistical variations of the essential rock properties, describing the architecture of the pore-system, have been included in the formalism. The upscaled result retains the familiar form of a Thomeer function while replacing single core plug values with their statistical equivalents. One of the important consequences is that intrusion of liquids for large pieces of rock can happen at much lower capillary pressures and thus much closer to the free water levels in oil reservoirs.
A New Production Allocation Optimization Framework
Authors: Guyaguler B. , Byer T.
Published: December 2007

Determination of the operating conditions of a field under a set of physical system constraints (e.g. compressor limits) and engineering preferences (e.g. voidage replacement) is a primary concern for petroleum engineers. Rule-based systems have been proposed for this but the process is most suitably defined as an optimization problem. An optimization procedure utilizing Mixed Integer Linear Programming (MILP) is proposed in this study. Well rates that honour system and engineering constraints are simultaneously handled while the maximum for an objective is sought (e.g. field oil rate or cash revenue). Optimal rates for the current conditions of the field are determined. Note that this amounts to instantaneous optimization, hence cannot account for recurrent events such as water break-throughs. Nevertheless, an efficient and robust instantaneous optimizer is useful within a grander optimization scheme, within short forecast periods and also in real-time allocation situations. The proposed approach is able to efficiently handle the nonlinearities in the system by way of piece-wise linear functions. Also due to the formulation of the problem, the exact optimal solution is guaranteed to be found. Another property of the approach is that, in cases where it is not possible to simultaneously honour all the targets and limits of the system, a scheme is introduced that allows the engineer to prioritize the constraints. This prioritization scheme proves to be of great practical significance since most real cases have conflicting targets and limits, which result in optimization systems with no feasible solutions. Also a heuristic is introduced and utilized, that ensures realistic results by the elimination of mathematical artefacts (rate oscillations in time) that often arise when the reservoir contains wells with similar properties (e.g. WOR and GOR). The optimization system is applied to synthetic cases and two real field cases. The real field cases pose problems that cannot be handled by conventional rule-based systems.