bluuebunny/crossref_metadata_2025 huggingface dataset:
Musallim Rim Near Field Exploration: New Concept Yields Big Value in an Old Field
Authors: Lawati M. A. , Harthy M. A. , Shuster M. , Willet A.
Published: December 2007

An exploratory appraisal campaign of the greater Musallim Oil Field area was executed in 2003. The main objective was to test the Shuaiba pancake reservoir and to confirm the presence of reservoir on the flanks, prove calibration of the porosity trends derived from acoustic impedance data, provide structural control and determine oil saturations below crestal oil-down-to (ODT) of 1443 mtvdss.

The appraisal campaign was designed to test the ODT pancake model concept in Musallim. The pancake concept is a model where 2-12m thick good reservoir zone overlies poor quality reservoir. Based mainly on oil saturations logged from vertical wells, this boundary was previously interpreted as an oil water contact. However saturation changes represent an ODT as a function of reservoir quality, and permeability in particular. Prior to this campaign, two existing flank wells, (Musallim Deep-1H1 and Tibr-1H1) targeted deeper reservoirs as their primary objective but found oil saturations up to 50% below the ODT of 1443 mtvdss, then defined as the OWC in the 2002 Musallim field FDP.

The 2003 appraisal campaign by PDO's Near Field Exploration team has proved the viability of the pancake model and significantly increased the reserves of the Musallim Field. It has extended the life of the field and opened up many new development possibilities. Another outcome of the exploratory appraisal campaign was that the eastern flank of the structure came in shallower and was confirmed by Tibr-2 which targeted deeper objectives that resulted in a re-assessment of the velocity model used in depth conversion. Success of the Musallim Rim campaign together with Tibr-2 well shows that these oil rims associated with the Shuaiba pancakes and flank plays are attractive targets.
Environmental Regulatory Framework in Europe: An Update
Authors: Garland E.
Published: December 2007

The legal framework in Europe evolves continuously. Regulations are implemented at national level, but the Europe Commission greatly influences the policy, especially onshore. Offshore, regional conventions, such as OSPAR for the North-East Atlantic still play a leading role.

There is not a single measure which can claim to have dramatically changed the way environmental issues are now regulated in Europe. But the sum of recent measures has substantially modified the still dispersed regulatory framework. And there is no doubt that this ground swell will continue to act in the near future: the Europe Commission already greatly influences most of the onshore policy. Offshore, regional conventions, in particular OSPAR, still play a leading role, but probably for a limited time. The industry has to adapt to that changes which do not relate any more solely to end-of-pipe constraints and techniques, but require a dramatic change in the approach of these issues, to identify and anticipate as early as possible the new technical challenges.
Assessing the Socioeconomic Impacts of Petroleum Exploration and Production Operations on Rural Communities in Southern Trinidad
Authors: Khan F. , Lalla F. , Roopchand J. , Dyal S. , Ramnath K.
Published: December 2007

An integral component of an Environmental Impact Assessment is the Socio-economic Assessment. The purpose of these assessments is to identify and evaluate potential impacts of proposed projects on the socio-economic environment of fenceline communities that would most likely be directly impacted by the project.

With the enactment of the Certificate of Environmental Clearance (CEC) Rules in Trinidad in 2001, Exploration and Production (E&P) companies must now apply to the Environmental Management Authority for an environmental permit for any activity designated under these rules. As a result, oil and gas operators in Trinidad have collected a significant amount of socioeconomic data as part of Environmental Impact Assessments (EIA’s) and Environmental Baseline Surveys for CEC applications.

The state owned oil company, Petrotrin, set the standard for conducting socio-economic assessments for energy development projects in Trinidad and did so on a voluntary basis before the CEC Rules were enacted using guidelines developed by the Regional Association of Oil and Natural Gas Companies in Latin America and the Caribbean (ARPEL).

In conducting socio-economic assessments, surveys were conducted for households, community leaders, business proprietors and focus groups. Generally 25% of the population are interviewed in the process to determine their views and aspirations on potential impacts of oil and gas E&P projects based on their historical experience. If effectively conducted, socio-economic assessments are a valuable tool for determining community needs and ensuring win-win partnerships between oil and gas companies and the communities in which they operate.

This paper describes the process by which Petrotrin has conducted socio-economic assessments for EIA’s and Environmental Baseline Surveys for fenceline communities where E&P development activities are planned. It also seeks to give an historical overview of how E&P operations have impacted fence line communities in southern Trinidad over the 20th century.
Automated Continuous Fluid Level Monitoring
Authors: Lieberman S.
Published: December 2007

Most well controllers require a pumping unit installation and difficult data analysis to determine and regulate for optimum well productivity.Wells with ESP's, PCP's or no pump (such as flowing wells, gas wells, etc.) require complicated and expensive equipment to accomplish the same goal.However, a wellhead-mounted, remote-operated, high-sensitivity acoustic fluid level "gun" has been developed which propels a "pressure wave" into the casing up to 100 times per day and sends the information (including casing pressure and other essential data) to any location (if desired).

Based on the information gathered (and automatically or manually analyzed), the units can be set to: regulate pumping speed; shut a well on and off ("time-clock" a well); trigger pump-off or other alarms; shut in safety valves; regulate chokes.In addition, the instrument's advanced "wave form" generation combined with an ultra-sensitive microphone can accurately detect the fluid level, perforations, holes in casing and tubing, paraffin/scale buildup, as well as down-hole equipment location within 5-10 feet in wells up to 20,000 feet depth.

Unlike most fluid level data, the information can be presented digitally on any computer, and adjusted to any sensitivity to maximize the accuracy of as well as the amount of data that can be gathered and utilized.Third-party analysis and monitoring can be arranged for companies that have minimal or no technical support.Important to note is that this technology is available for approximately the same cost as the well controllers offered by the industry today.Now one truly CAN "stick your head down there" and see just what's going on, as often as desired.

The advantages are obvious:minimize expensive electrical use; maximize life of well equipment; produce everything that enters the well; true determination of well productivity; prevent or quickly identify downhole problems; control wells safely onshore and offshore; identify gas well loading; minimize labor costs and human error.
Steam Injection Casing Design
Authors: Wu J. , Gonzalez M. E. , Hosn N.
Published: December 2007

Steam injection is a successful operation to increase heavy-oil production, but the casing failure rates in steam injection wells are very high. Severe thermal-loading to the casing is resulted from steam injection operations and is attributed to the high casing failure rates. The casing failures can be casing parted due to fatigue and/or tensile load at cooling period, and can also be casing ID restriction due to collapse and/or severe buckling. This paper will briefly review the common casing design practice, and provide mathematical modeling of casing stresses in steam injection wells, and discuss ways of reducing casing failures, including the use of high strength casing (such as P-110 grade) to reduce casing hot-yield in most steam injection wells.

The field data at Cymric 1Y field, Bakersfield, California are also presented to support the use of high strength casing (P-110 grade) in steam injection wells, based on the reduction of casing failures in the past two years.
Verification of an Advanced Analysis Model with Downhole Bending Moment Measurements
Authors: Neubert M. , Heisig G. , Forstner I. , Mounzer F.
Published: December 2007

Increasing BHA and wellbore complexity create a need for case specific engineering modeling software. Hence, mathematical modeling of the mechanical and dynamical behaviour of BHAs under various downhole conditions such as different wellbore curvatures has become routine. This paper discusses an advanced engineering model and the verification of its predictions with downhole measurements.

First the mathematical model and the downhole dynamics measurement sub are introduced. Next, three examples comparing measured and predicted steady state bending loads are presented. While the predicted and measured results match well, detail and accuracy of input parameters such as wellbore curvature are proven essential.

Lateral natural frequencies of the model are compared to the peaks in the measured frequency spectrum. In conclusion, the general validity of the model regarding bending loads and vibrations is evaluated.

Backward whirl dynamics is evaluated by comparing downhole measurements with time domain model simulations. The predictions meet the downhole measurements both in frequency and magnitude.
Quantifying Guar Polymer Recovery Post Hydraulic Fracturing to Determine the Degree of Fracture Cleanup: A Field Study of the Point of Rocks Formation, California
Authors: El Shaari N. , Kedzierski M. , Gorham T. L.
Published: December 2007

A field study was initiated to determine fracture cleanup by examining the carbohydrate content of flowback water production from a series of hydraulic fracture stages in the McKittrick field Point of Rocks formation. The study was an effort to understand hydraulic fracture cleanup of the Point of Rocks formation and obtain an idea on the amount of fracture volume contributing to production to optimize hydraulic fracturing design. The carbohydrate content and concentration measured from the water flowback samples are used as direct estimation to the amount of guar polymer recovered post-fracturing treatments. Carbohydrate estimation via anthrone testing method to quantify load recovery is by far the most accurate water analysis method available to the industry outside of injecting (and recovering) any special chemical markers. By contrast, studying the ionic content of produced waters by itself can be a misleading quantifier to load recovery due to the mixing and dilution of the pumped frac water with produced formation water. However, the accuracy of polymer quantification using the anthrone method is as accurate as the process of sampling, the frequency of sampling, the time from sampling to testing, the sample container, the testing method, and the calculations involved due to sampling frequency. This paper will discuss the anthrone testing method and will share guidelines that will enhance the accuracy of the testing process. The paper will also compare the guar polymer recovered from a number of hydraulic fracture stages in different Point of Rocks sands and compare to the amount of polymer pumped to present "hypothesis" as to the percent of the propped fracture actually contributing to production.
One-Trip Sand Control-Completion Technology That Eliminates Perforation Damage While Reducing Rig Time
Authors: Garfield G.
Published: December 2007

Formation damage caused by the perforating process is often found to be one of the leading contributors to poor productivity. Fractured and compacted zones, perforation gun debris, and broken formation blockages are common types of damage that can occur inside the perforation tunnel.

Reducing or eliminating initial perforation damage can result in a more productive well over its lifetime. This paper examines a completely new technology for perforating wells in unconsolidated formations that eliminates explosive perforation discharges and its associated formation damage risk. This new technology also reduces the cost of well construction by eliminating the need for perforating and by allowing the production liner and primary cementing equipment to be run in a single trip with an effective means of sand control.

The tool system uses telescoping tubes that extend from the liner to the formation by hydraulic pressure and mechanical force. Once the tubes are extended (or telescoped), the liner is cemented in place. The tubes form a conduit from the formation to the casing ID and contain sand-control media. This new completion method eliminates gravel packing and minimizes intervention in completion operations, saving substantial rig time. The system does not require large fluid-pumping treatments with high horsepower requirements, which simplifies operational logistics especially in remote or offshore environments.

Formation damage can also be caused by drilling mud and fluid-loss control measures after completion. This new perforating method eliminates both of these highly damaging mechanisms because the tubes extend out past the damage and into the formation, even in a washed out hole.

This paper describes the new system, cost comparisons with existing methods, and expected economic benefits over the lifetime of wells in typical applications of this new technology.
Potential Radon Emissions due to Biogas Generation at TENORM Land Disposal Sites
Authors: Walter G. R. , Benke R. R. , Pickett D. A.
Published: December 2007

Allowing disposal of technologically enhanced naturally occurring radioactive materials (TENORM) from petroleum exploration and production in non-hazardous waste landfills was proposed in a U.S. Deparment of Energy study. TENORM often contains radium that is a source of radon. Diffusion through soil and other cover materials is commonly regarded as the dominant radon transport process from land disposal units. Biogas generation in landfills may increase radon emissions relative to diffusion-dominated sites.

A numerical gas flow and transport model was used to simulate potential radon emissions from radium-bearing TENORM in solid waste landfills and land disposal sites where TENORM is co-disposed with oily waste. The landfill scenarios considered the effect of landfill gas generation potential and rate, cover construction, TENORM disposal method, and gas control methodology on radon emissions. The co-disposal scenarios investigated the effect of biogas generation rate, organic carbon partitioning, and cover construction on radon emissions. Gas generation was found to significantly increase radon emissions from landfills. Depending on the nature of the gas management system, atmospheric radon concentrations could exceed background level both on-site and off-site. The effect of biogas generation on radon emissions from co-disposal sites was found to be strongly dependent on the hydrocarbon content of the waste.

The results of this investigation provide guidance for selecting appropriate TENORM disposal options and for evaluating the potential environmental liabilities associated with the options.
Modeling Long-Term CO2 Storage in Aquifer with a Black-Oil Reservoir Simulator
Authors: Mo S. , Akervoll I.
Published: December 2007

This paper presents results of modeling long-term CO2 storage in a shallow saline aquifer with a commercial black-oil reservoir simulator. Realistic CO2/water phase behavior (pVT properties) covering all pressure, temperature and compositional conditions accounted for during the simulations have been used. The pressure and temperature in the aquifer is above the CO2 supercritical conditions giving rise to the existence of a two-phase fluid system of CO2 as a supercritical fluid ("gas") and CO2 dissolved in the aqueous phase. The objective was to model scenarios of CO2 storage in aquifer with emphasis on the sensitivity of CO2 distribution in the deposit with respect to critical CO2 saturations during the injection period and to residual CO2 saturation for water reentering CO2 filled volumes (hysteresis in fluid saturations). The re-distribution of water occurs after stop of CO2 injection due to gravity segregation of dense CO2 saturated water and CO2-free water. The impact of various reservoir parameters has been studied, including average permeability, vertical to horizontal permeability ratio (kv/kh), relative permeability, and capillary pressure. For the saturation functions the main focus has been on end points and hysteresis effects. It is observed that storage of CO2 as residual gas is most important for low kv/kh ratios.
Lightweight Cement, Ultrasonic Cement Evaluation, and Cased Hole Dynamics Formation Pressure Tester Combine to Enhance Infill-Drilling Opportunities in Shallow Marine Shelf Deposits, Kern County, California
Authors: Formica J. , Davis B.
Published: December 2007

Developed California oilfields are often under pressured. These low pressures and relatively high permeabilities present challenges in supporting mud and cement columns during well construction.

Accurate formation pressures are critical for petroleum exploitation. They are used for geological correlation, drilling/completion design, surface facilities design, and for reservoir management. Obtaining formation pressures in under pressured or tight reservoirs in open hole can be challenging due to poor hole conditions, thick mud cakes, risks of getting differential cable or tool stuck, and supercharging effects. These conditions can either compromise the formation pressure data quality and or result in formation pressure tool fishing operations.

This paper will show the results of a two well case study where lightweight cements of 9.8 ppg where successful run and evaluated for single stage cement jobs in a stacked reservoir with under pressured and over pressured formations. Then a cased hole formation pressure tool was deployed to get a combined total of twelve reservoir pressures after which the tool restored the casing to a condition that allowed for successful down the casing multi-stage high pressure proppant fracture jobs.

This combination of new technologies for mature reservoirs has given operators more options for well design and formation evaluation. Data quality and the answers uncovered have helped justified the continuation of infill drilling opportunities to increase production and reserves.
Evaluation of Two-Phase IPR Correlations for Horizontal Wells
Authors: Kamkom R. , Zhu D.
Published: December 2007

To predict well performance for horizontal wells, several analytical models have been developed to generate inflow performance relationships (IPR) for single-phase wells. Similar to vertical wells, analytical solutions of IPR in two-phase flow horizontal wells are unavailable because of the complexity of relative permeability and the variable phase distribution in the reservoir. Correlations, lead by Vogel's equation, have been used for two-phase IPR calculations for vertical wells, and the methods have been adopted for horizontal well applications.

This paper reviews several two-phase correlations for horizontal wells (Bendakhlia and Aziz's equation, Cheng's equation, and Retnanto and Economides’ equation). Instead of using the original formula of Vogel's equation, these models include the effects of reservoir recovery factor or fluid bubble-point pressure on IPR behaviors. We also presented a modified Vogel's correlation for two-phase horizontal IPR following Kabir's work. The modified correlation uses Babu and Odeh's single-phase horizontal well model to calculate the absolute open flow potential, qo, max, and then uses the original Vogel's correlation to generate the relationship between flow rate and pressure. The reservoir anisotropy is considered in Babu and Odeh's model for horizontal well flow. The results of the modified Vogel's equation are compared with the reviewed two-phase correlations, and also checked against the results from a reservoir simulator (Eclipse™). It is found that the modified Vogel's equation results in close predictions of two-phase inflow performance for horizontal wells at normal recovery factors compared with the reservoir simulation results. At low recovery factor, it deviates from the simulation results more than some other correlations reviewed. For low bubble-point pressure fluids, flow conditions in the reservoir are more likely to be single-phase rather than two-phase, and gradually tranforms from single-phase to two-phase flow as the reservoir pressure declines. The modified Vogel's inflow equation does not capture this transient period; neither do the other correlations reviewed in this paper.

The modified Vogel correlation for two-phase flow horizontal wells is simple compared with the other models, and works as well as the other models at the normal flow condition. It can be used to estimate horizontal well performance conveniently.
New Considerations for Modeling Plunger Performance
Authors: Garg D. , Lea J. F. , Cox J. , Oetama T.
Published: December 2007

The rising portion of plunger cycle makes use of some type of designed sealing mechanisms on the plunger. These sealing techniques reduce the amount of gas that bypasses (leakage) the surfacing plungers. When falling, many plungers have mechanisms designed to allow increased leakage or slippage enabling the plungers to fall faster.

Modeling techniques, for leakage about a rising plunger, shown in this paper are shown as analogous to orifice type flow restriction. For fast falling plungers the model is developed is similar to objects experiencing drag in a field of gas velocity. Data collected for this type of modeling is presented from suspension tests and confirmed with dynamic test data. Model ratification is done with some dynamic test data. Special two-piece and conventional plungers are hereby modeled from suspension and dynamic testing.

The results should help the operators to select specific plunger hardware for specific conditions and should assist in modeling plunger cycles.
Managing Process Risk of Field Facilities
Authors: Johnstone J. E. , Jensen J. R. , Stegall R. P.
Published: December 2007

Managing the risk of oil and gas field facilities is necessary to assure that operations do not pose a significant hazard to the public or those individuals who operate and maintain them. This paper reviews the efforts of BP to implement a company-wide program to manage the risk of oil and gas field facilities.

The growth of BP over the past few years has brought together properties from many different companies in varied geographic locations. BP was challenged with having to safely operate thousands of wells, pipelines, compressors and field separation facilities built to different standards, throughout several generations, in many different states. A new approach was needed to provide assurance that these facilities were constructed and operated safely.

The process to assure that facilities were constructed and operated in a safe manner was broken down into series of steps. The first step was to define risk factors. These factors included rates, pressures, proximity to public areas and the composition of produced fluids. After defining the risk factors, it was necessary to establish design and operational requirements to mitigate the risk. These included use of safety devices, facility design, hazard mitigation measures and management systems. Next, each facility had to be "graded" against the risk factors to determine the relative risk of each facility. Equipment, operational or management system changes had to be next determined for each facility, if necessary. Finally, modifications to the equipment or operating systems to mitigate the risk were implemented.

This paper discusses each of these steps in detail, which BP employed to mitigate operational risk at its oil and gas field facilities.
Applying a Reservoir Simulation Model to Drill a Horizontal Well in a Post-Steamflood Reservoir, Wilmington Field, California
Authors: Hara P. S. , Mondragon J. J. , Sun H. H. , Yang Z. , Ershaghi I.
Published: December 2007

This paper is a case study on the use of a simulation based reservoir evaluation method that led to the drilling of a new well in a seemingly semi depleted steam flooded part of a Fault Block in the Wilmington Field, California. Observations made on this well led to the initiation of a very progressive re-development plan for the area. Information generated from the study should be of significant help for re-development of countless similar field operations that have undergone prior thermal flooding.

The City of Long Beach (City) and Tidelands Oil Production Company (Tidelands) drilled and completed a post-steamflood horizontal producing well, UP-957, into the D1 sands of the Fault Block II-A Tar Zone (Tar II-A) in the Wilmington Field, California in March 2004. The well was directionally drilled along the top and most updip structural position of the D1 Sands. The well penetrated the oil-depleted steam chest interval in the main steamflood area and was completed in a relatively immature steamflood area into the highest remaining oil saturated sands in the Tar II-A. The completion interval was selected based on a 3-D deterministic reservoir simulation model with thermal capabilities developed as part of a United States Department of Energy Class III Reservoir project. Prior to this operation, the developed model was successfully used to convert the Tar II-A steamflood operation to a post-steamflood operation. The model employed a flank cold-water injection strategy between two faults to increase and maintain reservoir pressures to prevent steam chest collapse and surface subsidence1.

Well UP-957 produced at a peak initial oil rate of 249 BOPD and 723 barrels of gross fluid at a wellhead temperature of 197°F and a pumping fluid level of 2122 ft over the mid-perforation depth of 2403 ft VSS (vertical subsea depth), confirming the potential shown by the model. Since the initial response, the oil rate has declined to 130 BOPD and 1991 BGFPD after nine months of production.
Novel Technique for Improved CT Access and Stimulation in an Extended-Reach Well
Authors: Nasr-El-Din H. A. , Arnaout I. H. , Chesson J. B. , Cawiezel K.
Published: December 2007

Drilling technology advances have extended the reach of well depths and complicated trajectories which have in turn created challenges for rig-less well intervention around the world. Extended reach horizontal wells up to 25,000 ft deep require that coiled tubing designs be carefully analyzed to determine when weight stacking and lock-up will prevent coiled tubing from reaching the desired total depth. If the well requires stimulation, then the benefit of coiled tubing is its enhanced placement capability to uniformly inject a treatment across a desired interval. An effective treatment diverting method can further improve these results, especially when coiled tubing is not able to access the entire pay interval. When coiled tubing locks-up before reaching the total depth for one of these treatments, a decision must be made to bullhead the treatment into the lower unreachable section, hoping for uniform placement, or to employ technology which can extend the reach. Larger diameter coiled tubing, coil tractors, liquid friction reducer, mechanical vibrational friction reduction, and buoyancy effects are techniques which can extend the reach of coiled tubing.

Sensitivity analysis was run for the aforementioned techniques and a new vibrational tool combined with a liquid friction reducer on 2-inch coiled tubing was chosen to successfully acid stimulate a horizontal open hole well. This configuration allowed the coiled tubing to reach 25 percent further than the initial lock-up point and the combination of this technique with a new viscoelastic surfactant diverting system, successfully treated the damaged well for a gain of 6,000 BOPD.

This paper will review the stimulation design process and three innovative technologies which have been combined with coiled tubing to successfully treat extended reach wells in Saudi Arabia.
Interpretation of Temperature and Pressure Profiles Measured in Multilateral Wells Equipped with Intelligent Completions
Authors: Yoshioka K. , Zhu D. , Hill A. D. , Lake L. W.
Published: December 2007

This paper presents methods to interpret measurements in complex wells (horizontal, multilateral and multi-branching wells) to determine the inflow profiles of oil, gas and water. These methods are needed to take full advantage of intelligent well, a technology that is rapidly evolving to continuously and permanently monitor downhole temperature, pressure, and perhaps volumetric flow. To realize the value of intelligent wells, the efficient and accurate interpretation of the raw data being acquired is needed.

The interpretation of flow profiles of horizontal or multilateral wells from temperature and pressure profiles requires consideration of subtle effects that are often neglected. In this paper, we illustrate how some of these effects can be predicted, and how they can be used to evaluate complex well performance. In particular, we will highlight the following characteristics of flow in horizontal wells, each of which can provide information about the inflow profile of the well.

Firstly we discuss about Joule-Thomson effects (the heating of oil and the cooling of gas) on the temperature profiles, seeing if they are noticeable changes or not. The discrete production cases are then considered to infer how the pressure or temperature profiles retain marks where the production starts and ends. Also, we examine well trajectories effects. Small inclinations (+2° and -2°) in nominally horizontal laterals affect both pressure and temperature profiles. The differences in potential energy in up-inclined and down-inclined segments may prove to be diagnostic of relative flow rates of the phases. As a last example, water entry effects on the each profiles are shown. When the production becomes oil and water two-phase flow, the fluid properties change and affect the both profiles. In certain cases, the location of the water entry may be noticeable.
Primary and Secondary Oil Recovery From Different Wettability Rocks by Countercurrent Diffusion and Spontaneous Imbibition
Authors: Hatiboglu C. U. , Babadagli T.
Published: December 2007

This study investigates optimum matrix oil recovery strategies in naturally fractured reservoirs (NFR) for different wettabilities and rock types. We compare the recovery efficiencies of two cases: (a) the primary counter-current spontaneous imbibition followed by the diffusion of a miscible phase (secondary recovery) and (b) primary diffusion of miscible fluid without pre-flush of matrix by the spontaneous imbibition. For these recovery strategies, the effects of the matrix shape factor, matrix wettability, and type of miscible displacing phase on the rate of recovery and development of residual oil saturation were clarified experimentally.

Cylindrical Berea sandstone and Indiana limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically situated samples where the matrix-fracture interaction took place upward direction. Mineral oil and crude oil were used as oleic phases. Brine was selected as aqueous phases for the primary spontaneous imbibition recovery. For primary and secondary miscible displacement experiments n-heptane was used as solvent. Wettability of water-wet Berea sandstone samples was altered to weakly water-wet to observe its effects on the dynamics of spontaneous counter-current imbibition and diffusion.

Parametric analyses were performed for the appraisal of secondary and tertiary recovery potential of naturally fractured reservoirs by immiscible and miscible fluid injections. The optimal recovery strategies (recovery rate, recovery time and ultimate recovery) for different rock properties were identified and classified. In water-wet cases, starting the recovery with capillary imbibition followed by diffusion was found the optimal way, i.e. both effective and efficient. For limestone or aged sandstone samples, starting the recovery by diffusion yielded a faster recovery rate and higher ultimate recovery.
Valhall Field Coiled Tubing Post-Fracture Proppant Cleanout Process Optimization
Authors: Zhou W. , Amaravadi S. , Roedsjoe M.
Published: December 2007

The standard well-completion method in the Valhall field has evolved since 1996 to include multiple proppant fractures along the horizontal laterals. Coiled tubing (CT) has been used since then to perform over 200 post-fracture proppant cleanout operations. Field practices were developed from these jobs but the process in different stages of proppant cleanout operations had not been systematically optimized to realize best performance until the launch of a new process to optimize CT proppant cleanouts.

In May 2004, a study of proppant cleanout process optimization was completed by analyzing historical cleanout performance and incorporation of a new, integrated wellbore-cleanout system to improve operational efficiency through optimized processes, improve safety and reliability by implementing standardized procedures, and reduce stuck-pipe potential through improved design. This study analyzed the whole process of proppant cleanout, captured best practices through validation of field experience, introduced innovations to routine operations, and engineered a new, more efficient cleanout procedure for field operations.

The field implementation of this new process optimization on the first three wells, a total of 22 zones, indicated a significant performance improvement. The optimized process saved a total of 6 days’ working time and encountered zero incidents that might have led to stuck pipe. The new cleanout procedure was followed by different operational crews on the job and has been adopted as a best practice for future wells.

This paper details the engineering and implementation of CT post-fracture proppant cleanout process optimization in the Valhall field and demonstrates a step-change improvement in Valhall CT cleanout performance during the past 9 years.
Successful Coiled Tubing Water Shutoff Solution for a Horizontal Sand Screen Completion Using Novel Fluids
Authors: Tudball I. , Mcginn P. , Watson D.
Published: December 2007

This paper describes the results obtained, the techniques used, and the challenges involved in providing a water shutoff solution to a subsea gas production well with a sand screen completion on the Rose field in the UK Southern North Sea.

The project began with a detailed reservoir analysis to determine if intervention was practical in this subhydrostatic well. This led to the planning and sourcing of suitable coiled tubing (CT) and pumping equipment, as well as an associated zonal isolation chemical solution.

The design of the intervention was tailored to operate within the environment of a jackup installation located over a subsea well. This included CT and fluid pumping operations. The basis of the technique was to shut off the water-producing interval in the horizontal completion and isolate the unsupported annulus between the water bearing and gas producing intervals. The greatest challenge was to isolate the horizontal annulus between the gas and water producing zones. This required setting of mechanical barriers and the placement of suitable zonal isolation material that would set quickly without slumping and leaving the top of the annulus unsealed. This paper details the lessons learned throughout the intervention.

In the case of the Rose well, it now produces dry gas. This was the first time globally that this technique had been applied to a subsea horizontal well.
Reservoir Monitoring with Pulsed Neutron Capture Logs
Authors: Morris C. , Aswad T. , Morris F. , Quinlan T.
Published: December 2007

Efficient reservoir management requires that the latest pulsed neutron capture (PNC) tool technology be comparable with the older measurement results to provide continuity, precision, and accuracy in the monitoring program. A new sigma processing technique was developed for the dual-burst pulse neutron capture measurements that maintains the resolution and repeatability of the new-generation tools but provides results needed for reconciliation with the older generation tools used for more than 20 years in reservoir monitoring. The sigma processing technique is described relative to the old and new generation tools, which utilize radically different approaches. General considerations of repeatability and accuracy are discussed which apply to PNC logs and their use in both stand-alone and time-lapse techniques.

More than 35 cases have been evaluated with the new processing technique. Examples are presented to show reservoir monitoring results obtained in a variety of formation lithologies, formation fluids, and borehole environments to illustrate the robustness of the technique. These cases include detailed analytic studies between the PNC tools. The results indicate that the new sigma processing can provide direct time-lapse reservoir monitoring continuity and yield accurate reservoir saturation analysis.
The Application of a Reduced Polymer Borate System
Authors: McDonald C. E.
Published: December 2007

The amount of polymer damage created by a fracturing system has been a problem for many years. Polymer damage results in the reduction of fracture conductivity and effective propped fracture length. One method to reduce polymer damage is to reduce gel loadings. Historically systems that were developed to reduce polymer loadings have encountered numerous problems. The limiting factor for reducing the amount of polymer in a fracturing system is the point where the viscosity of the fluid is not adequate to transport proppant. In areas of low permeability gas wells, poor proppant transport results in less than desired production due to decreased fracture length in the reservoir.

Many of these low-polymer fracturing systems are not operationally feasible due to the lack of a suitable water source for the system to yield its peak viscosity. In addition to the operational issues of locating a suitable water source, another constraint on some of these systems is the requirement to use a liquid KCl substitute in place of granular KCl. These issues have limited the use of the low-polymer systems in many areas. The shear sensitivity associated with the use of organometallic crosslinkers is a problem encountered by many low-polymer systems. High tubular velocities will shear degrade the fluid reducing it's proppant transport capability compared to that of a borate crosslinked system.

This paper will discuss a modification to a well-established borate crosslinked fluid and system that eliminates these problems. Case histories will be given for the applications and results of this reduced polymer system that yields comparable viscosities to higher polymer loading systems.
Waterflooding in Chalk: Relationship between Oil Recovery, New Wettability Index, Brine Composition and Cationic Wettability Modifier
Authors: Zhang P. , Austad T.
Published: December 2007

Naturally fractured carbonate reservoirs are usually neutral to preferential oil-wet, which prevents water from being an efficient IOR-fluid. Spontaneous imbibition of water into the matrix blocks is believed to be the key mechanism for improved oil recovery by waterflooding. In previous study, it was documented that the wetting condition of carbonates was mainly dictated by the acid number, AN, of the crude oil. In the present study, series of long-term spontaneous imbibition tests were conducted at 70°C on chalk cores representing different wetting conditions. The oil recovery is discussed in terms of a new wetting index and the property/composition of the imbibing fluids. Synthetic seawater was used as the base imbibing fluid, and model Ekofisk formation water was used as initial water present in the cores. The cores were aged in crude oils with different AN and at a variety of temperatures ranging from 40-120°C. Major observations are: (1) Good relationship between the new wetting index and oil recovery was established. (2) The water-wet fraction of the chalk surface must be above 0.6 for spontaneous imbibition to occur.(3) Sulfate in the imbibing fluid appeared to have a wettability modifying effect, especially at low water-wet conditions. (4) Cationic surfactant of the type [R-N(CH3)3]+ dissolved in the imbibing fluid improved the oil recovery significantly, especially close to neutral wetting conditions. The effects of sulfate on the oil recovery is discussed in terms of potential determining ions towards chalk, as well as its potential as wettability modifying agent.
An Interwell Water Flood Study: Flow Pattern and Reservoir Heterogeneity Evaluation of a Northern Field Formation in Mexico, Part I: Upper Section of the Field
Authors: Reyes-Lopez C. , Marhx-Rojano M. A. , Asadi M. , Casas D. R.
Published: December 2007

A successful reservoir flood depends on prior knowledge of the flow stream within a reservoir and a proper injection/production pattern. A northern field formation in Mexico, which currently includes 44 injectors and more than 150 producers, has been under water flood since early 1965. Due to the loss of injection fluid and low sweep efficiencies a chemical interwell tracer program was designed and implemented to fully investigate the flow stream within the current injection/production pattern and to evaluate reservoir heterogeneity. However, based on the results of seismic and well test analysis and due to the large number of active injection and production wells, the entire field was divided into four sections for this interwell tracer study. This paper presents the interwell study results for the upper section of the north field, which includes seven injectors (A to G) and 36 producers (1 to 36). A detailed interwell study over a 10 month period indicated the existence of massive high-permeability channels as well the existence of a major fault initiating from this section and extending downward into the lower section of the field. Also, the results indicate the existence of several transverse faults along the main fault. Detailed graphical results to identify the flow stream, a comprehensive interpretation of the heterogeneity of the formation, and tracer travel time are also presented.
Post-Perforation Flow Models for API Recommended Practices 19B
Authors: Roostapour A. , Yildiz T.
Published: December 2007

Flow tests conducted on standard cylindrical Berea targets are used to evaluate the relative merits of jet perforators. The procedure and equipment for the flow tests are described in the API Recommended Practices 19B revised recently. The performance of the perforators is quantified in terms of core flow efficiency (CFE).

The CFE is the ratio of the actual post-perforation flow rate measured on the core to the theoretical ideal flow rate calculated from the mathematical models considering post-perforation flow geometry. The post-perforation flow tests may be conducted in several different flow geometries; axial flow, semi-radial flow, and radial-axial flow.

This study presents analytical solutions to predict the ideal rates for the complicated post-perforation flow configurations. The proposed solutions are compared against the existing numerical models and verified. The analytical solutions are general, and very fast and inexpensive to compute.

After verifying their accuracy, we use the solutions to evaluate the validity of the API recommended procedure and analysis technique. We demonstrate that the post-perforation flow geometry, core/perforation dimensions, permeability anisotropy, and the degree of formation damage control CFE. The same degree of formation damage yields different CFE in different post-perforation flow geometries. Finally we introduce a method to convert the CFE data to an equivalent skin factor for the perforated wells.
Determination of Parameters for Matrix-Fracture Transfer Functions From Laboratory Data
Authors: Civan F. , Rasmussen M. L.
Published: December 2007

Improved matrix-fracture interface fluid transfer functions for naturally fractured reservoirs are formulated and the associated parameters are determined by experimental data. Hindered-fluid transfer across the matrix-fracture interface due to skin effect is considered. Applications for single phase oil or gas production by pressure depression and oil production by immiscible displacement are accomplished by means of dimensionless phenomenological equations. Analytical solutions are derived for special boundary conditions involving the typical laboratory tests and reservoir simulation to represent the various matrix block shapes. The present analytical solutions involve the skin effect, anisotropic porous matrix, properly scaled variables, and full-time solutions and asymptotic solutions for early- and late-time periods. These solutions are obtained after proper linearization of the porous matrix fluid transfer model for one-, two-, and three-dimensional Cartesian matrix blocks, circular-cylinder and annular shaped matrix blocks, and spherical matrix blocks. The characteristic parameters of the transfer functions, namely the diffusion coefficient, skin coefficient, and skin thickness, are determined by conforming special analytical solutions to experimental data involving fluid exchange between matrix and fracture by imbibition.
The Application of Microemulsion Additives in Drilling and Stimulation Results in Enhanced Gas Production
Authors: Penny G. , Pursley J. T. , Holcomb D.
Published: December 2007

A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations.The microemulsion (ME) is an optically clear, thermodynamically stable blend of biodegradable solvent, surfactant, co-solvent and water.The nanometer sized structures have extremely high contact efficiency at low concentrations (0.10-0.5%).

Lab data is presented that illustrates how the Microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle.It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture and longer effective frac lengths.Examples of drilling fluids with and without ME are shown in which the relative perm to gas and oil are improved with the application of the microemulsion system.

Field examples are shown for fracture treatments of unconventional low permeability coals and shales, where water recovery and productivity are increased by 50% with the application of ME. A production analysis is presented for wells treated in the Barnett Shale that shows longer effective frac lengths and decreased damage surrounding the fracture.