bluuebunny/crossref_metadata_2025 huggingface dataset:
Research Progress of Modelling on Cold Heavy Oil Production with Sand
Authors: Pan Yi , Chen Zhangxin , Sun Jian , Bao Xia , Xiao Lizhi , Wang Ruihe
Published: July 2010

Heavy oil has been playing a critical role in today's world energy supply. The total amount of heavy oil in place is five to ten times greater than that of the current proven conventional crude. One of the recovery methods, which produces both oil and unconsolidated sands, is known as Cold Heavy Oil Production with Sand (CHOPS). The advantages of CHOPS lie in its commercial success as an inexpensive start up application for heavy oil reservoirs as well as its considerable recovery rates. The general reservoir characteristics associated with successful applications of CHOPS have been established, particularly highlighted in thin reservoirs with non-active edge and bottom water. Heavy oil researchers have accumulated local knowledge for the CHOPS fields; particularly, research groups in Alberta have taken integrated approaches to the questions posed by the field success of cold production. CHOPS gives high early production rates and becomes very efficient in the thin reservoirs where some thermal methods have been economically unsuccessful.

Aggressive sand production was encountered in California prior to the First World War. Two key mechanisms lead to the success of cold production in laboratory and field studies: foamy oil flow and wormhole network growth. A variety of numerical models are presented and compared in this paper. Such models can be mainly divided into two broad categories: preliminary model and comprehensive model. With a large number of variables still in limited recognition for the complex mechanisms, several models lack capability in fully simulating CHOPS processes, while progress was achieved in modeling the reservoir heterogeneity with the integration of seismic attributes at specific fields. A detailed discussion of the strengths and weaknesses of cold production models is proposed. The paper ends with the future work of modeling proposed on cold production.
Chemical Treatment to Mitigate Condensate and Water Blocking in Gas Wells in Carbonate Reservoirs
Authors: Ahmadi M. , Sharma M. M. , Pope G. A. , Torres D. E. , McCulley C. A. , Linnemeyer H.
Published: July 2010

Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements and drop imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests.

An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We demonstrate measured relative permeability values in Texas Cream limestone cores (TCL) from high-pressure, high-temperature (HPHT) coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with a synthetic gas-condensate mixture. To enhance the durability of the treatment a special amine primer is introduced. The gas relative permeability increased considerably, about 80%, after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more then 1000 pore volumes (PV) of gas-condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PVs of brine and increasing the temperature in the treated core from 175 °F to 275 °F.

The chemical treatment developed in this research can be applied to increase well deliverability and final recovery of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.
Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource
Authors: Young J. P. , Mathews W. L. , Hulm E. J.
Published: July 2010

Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River Unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped due to the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy oil resource are primarily technology and favorable economics. This paper is focused solely on the technology hurdles.

Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. The combination of low well rates, high costs, and arctic conditions require a sustained commitment to developing new approaches for unlocking the resource. To progress this opportunity BP initiated an appraisal program involving resource characterization, production pilots, and development screening. This paper describes early appraisal results from a cold heavy oil production with sand (CHOPS) flowback and multi-zone drill-stem testing to obtain quality reservoir fluid samples.
Simulation of Time-lapse Mineral Carbonation and Isotope Fractionation of Injected CO2 in Aquifer: Implications for Monitoring CO2 Sequestration
Authors: Jung W. , Yang D.
Published: July 2010

A theoretical aquifer model predicts time-lapse mineral carbonation and isotope fractionation of injected CO2 in sediment. Geologic sequestration of CO2 has become one of the promising ways to reduce atmospheric emission of CO2 from human activity. However, the current and future effects of geologic storage after injecting CO2 are not known well. We developed a simple mathematical model based on a transport-reaction equation and calculated the abundance of carbon stable isotope in the reservoir with respect to time which allows us to predict CO2 saturation in sediment or CO2 flume distribution by ground reservoir water. These results indicate significant potential of the theoretical aquifer model for monitoring and verification of CO2 sequestration into the sediment.
Density of High Pressure and Temperature Gas Reservoirs: Effect of Non-hydrocarbon Contaminants on Density of Natural Gas Mixtures
Authors: Tabasinejad F. , Moore R. G. , Mehta S. A. , Van Fraassen K. C. , Barzin Y. , Rushing J. A. , Newsham K. E.
Published: July 2010

New experimental density data are generated in this study for light and heavy dry gas mixtures. The light mixtures consist mostly of methane and small fractions of ethane, propane, and nitrogen. Normal alkanes up to C6, iso-butane and iso-pentane together with carbon dioxide form the heavier gas mixtures. For each mixture, isothermal gas density is measured from 3.45 MPa to 140 MPa at temperatures of 423.15 K and 478.15 K. Effects of CO2 and N2 as two non-hydrocarbon contaminants, on density of gas mixtures are examined in steps of 5 mol%, 10 mol%, and 20 mol%. In addition, water vapor influence on gas phase density of water-saturated gas mixtures is also investigated. Different correlations for sweet and sour gas critical properties are combined with the most widely used equations of state (Hall-Yarborough and Dranchuk-Abou-Kassem) to predict density data for comparison with 450 experimental measurements. The most important results demonstrated from this study are:

Among all correlations, the combination of the Hall-Yarborough equation with the pseudo-critical properties correlated by Sutton generates the lowest average absolute deviation (AAD) between predicted and experimental density data. The correction term developed by Wichert and Aziz to modify the pseudo-critical properties due to the presence of non-hydrocarbon compounds in the gas mixture, drastically improves the prediction of density data. At very high pressure and temperature conditions, effect of water vapor becomes more significant on gas phase density and it should be considered in density related correlations.
Development and Field Pilot Test of a Novel Viscoelastic Anionic-Surfactant (VAS) Fracturing Fluid
Authors: Zhang Jin , Zhang Mei , Zhang Shicheng , Bai Baojun , Gao Zhen
Published: July 2010

A novel fracturing fluid called VAS (anionic surfactant type) has been successfully developed and applied in both oil and gas wells in China. VAS can not only minimize matrix damage caused by modifying the rock surface charge and lowering watersensitive and water-lock. This paper presents the stimulation mechanisms of the novel VAS fracturing fluid. Field demonstrations indicate that, for the wells using the VAS fracturing fluid, the production increased remarkably and stabilized longer than the wells using water-based Guar gum fracturing fluid. Averagely, the production for the wells using this VAS fracturing fluid increased by 120% compared with the wells using acidic fracturing fluid and increased by 89% compared with the wells using ethyloic fracturing fluid.
A New Model for Predicting Inflow Performance of Fractured Horizontal Wells
Authors: Yuan Hong , Zhou Desheng
Published: July 2010

Based on the analysis of horizontal well flow and flow characteristics in fractures, this paper presents a new method to predict the inflow performance of fractured horizontal wells with single phase flow at steady state conditions.

More and more horizontal wells are drilled today and we encounter more fractured horizontal wells. While predicting the inflow performance of fractured horizontal wells, we found that there is a need for a new model which couples the flow from rock matrix and flow from fractures, and is applicable for horizontal wells both with and without fractures. The model presented in this paper serves the purpose.

The presented model can be easily used in horizontal wells with or without fractures. Results from the new model are compared with those from commonly used models in petroleum industry for fractured and unfractured horizontal well flow models such as Economides et al., Joshi, Babu and Odeh, and Guo and Schechter. Results from the new model are also compared with field data obtained from published literature.

The new model may be used in well planning, production design, production system analysis and well efficiency improvement.
Storage and Output Flow From Shale and Tight Gas Reservoirs
Authors: Rahmanian Mohammad , Solano Nisael , Aguilera Roberto
Published: July 2010

Crossplots of porosity vs. permeability from various North American basins show that there is a continuum between conventional, tight and shale gas reservoirs. This is significant as some of the key issues, particularly in shale and tight gas reservoirs, are having good estimates of storage and flow capacity. The crossplots include data from the Fayettville, Barnett, Ohio and Marcellus shales in the United States; Horn River and soft shales in Canada, tight gas Nikanassin formation in Canada and several conventional North American gas reservoirs. The data used in the crossplots have been obtained from plugs, crushed samples and drill cuttings.

The results permit integration of the storage and potential gas deliverability for determining flow units and other important characteristics such as brittleness and/or ductility, hydraulic fracturing alternatives, effect of water saturation and mud filtrate; and differentiation between viscous and diffusion dominated flow. Examples of simulation at the pore throat level, from which it is possible to estimate petrophysical, rock-fluid interaction and rock mechanics properties, are presented.

The storage and flow capacity in the case of stacked layers, or lateral variations of conventional, tight and shale gas formations, are discussed in detail. The data suggest that permeability determinations from crushed shale samples might be pessimistic as they do not take into account the possible presence of microfractures and pores in organic matter within shale matrix.

It is concluded that crossplots of porosity vs. permeability are very powerful for distinguishing and evaluating storage and flow capacities of conventional, tight and shale gas reservoirs. The concept of flow units in shales and tight gas, and its differentiation from conventional formations, should prove powerful in future simulation work.
Permeability Estimate for the South Ellwood Fault
Authors: Boles J. , Horner S. , Garven G.
Published: July 2010

Fault-zone permeability kf has been estimated for an offshore well in close proximity to the South Ellwood fault at Platform Holly, Santa Barbara channel, California. This fault runs parallel to the axis of the structure of the South Ellwood field, which produces from the Monterey Formation that has a mean permeability of about kf ~ 10 md about 1 km (3000 ft) beneath the sea floor. The pressure has been 77% of hydrostatic since 1984. Tidal frequency pressure variation from a shut-in well (Well #13) completed close to the fault, indicates the reservoir is in local communication with the sea bed via the fault zone.

Our permeability estimate comes from Well #7, completed about 5.2 km (3.2 miles) southeast of Well #13. Steel tents that overlie Well #7 on the sea bed capture gas seeping from the damage zone of the South Ellwood fault. When Well #7 is shut down, seepage production increases by about 1.0 Mm3/D (35 Mcf/D) to 1.6 Mm3/D (60 Mcf/D) over shut down periods ranging from 21 days in 2003 to 45 days in 2005, respectively. Using these changes in flow rate and the pressure differences between the seep tents and the perforation intervals in the well, we have calculated kf = ~30 md with respect to gas for the approximate 1 km (3000 feet) long fracture/fault flow path with an average cross section of 1860 m2 (2.0 × 104 ft2), based on Darcy's equation. Our fault-zone permeability estimate indicates that the damage zone of a fault can have a relatively high kf vertical value over a kilometer scale.
Simplified Yet Rigorous Forecasting of Tight/Shale Gas Production in Linear Flow
Authors: Nobakht M. , Mattar L. , Moghadam S. , Anderson D. M.
Published: July 2010

This paper presents a simplified, yet rigorous, method of production forecasting for tight/shale gas reservoirs exhibiting extended periods of linear flow, without the use of complex tools. The method is simple as it relies principally on a plot of inverse rate versus square root time, and it is rigorous in that it is based on the theory of linear flow and combines the linear flow transient period with hyperbolic decline during boundary-dominated flow.

The dominant flow regime observed in most fractured tight/shale gas wells is linear flow, which may continue for several years. This linear flow will be followed by boundary-dominated flow at later times. Therefore, the method proposed in this study is applicable for forecasting production data for these wells, as it considers these two important flow regimes.

The method is validated by comparing its results against test cases which are built using numerical simulation. For each case, only the first year of the synthetic production data is then used for the analysis. It is found that there is excellent agreement between the forecast rates obtained using this method and the numerically simulated rates.

Currently, analysis techniques using material balance time are being used in industry to analyze shale/tight gas reservoirs. Because material balance time is actually boundary-dominated flow superposition time, these analyses may show symptoms of boundary-dominated flow even though the reservoir is still in transient flow. Here are the advantages of the forecasting method proposed in this study: (1) It is not biased towards any flow regimes, as no superposition time functions are used; (2) Reliable forecasts can be obtained without using pseudo-time-this is an advantage, as using pseudo-time introduces complexities and an iterative procedure; and (3) The only externally specified parameter required is the drainage area.
Integrated Risk Analysis Criteria for Managing Exploration and Development of Oil and Gas Assets
Authors: Belhaj Hadi , Haroun Mohamad , Lay Terry
Published: July 2010

Current petroleum industry practice (as reported by Beucher et. al.1 and Bratvold and Begg2 etc. AAPG 2008) adopts schemes that aim at separating risk into two main categories; subsurface risk that includes resource size, production rate, and access cost and surface risk that demonstrates total expenditure, facilities delivery, delays, performance, oil/gas revenues and costs.

A recent SPE review (Bartvold el al SPE RE 2009) of decision making in the petroleum industry shows great dependence on VOI (Value of Information), to manage risk. VOI cannot stand alone as a decision making tool. There are also shortcomings in the use of Monte Carlo simulation.

In this paper, we introduce an integrated approach for handling risk associated with oil and gas exploration as well as development of mature reservoirs through EOR and IOR. Test case includes a major asset in the Arabian Gulf Region selected due to its varying reservoir settings.

The proposed approach basically, integrates uncertainty elements that may create "business risk" causing "business impact". This solution methodology breaks down each risk parameter to sub-parameters. Critical and non critical sub-parameters are broken down to even more detailed pieces of risk components, down to the smallest fragments of risk. Thereafter, a down-to-top risk analysis technique is adopted to reach to target NCF (Net Cash Flow).

Proposed is a tool for risk analysis modeling criteria related to exploration of oil and gas, and development of mature fields. In particular, it focuses on comprehension and inclusion and negates lumping/dropping of any risk parameter. This is not only because petroleum industry is surrounded by lots of uncertainties and therefore carries a huge risk, but also because other economies are revolving and highly dependent on this industry. In many cases, ignored risk parameters, that once thought non-critical, turned to business disasters.
Thin Oil Columns Horizontal Wells Optimization Through Advance Well Placement Application in West China
Authors: Xin Song Yu , Xin Mai , Lin Du Hong , Qing Li , Hua Zhang Zhong , Halomoan Parlindungan M. , Bin Yang , Mi Zou , Yang Liu , Koon Lee Tow
Published: July 2010

Lu Liang is an oil field that has been producing for nearly 10 years. Thus, bottom water level has increased and accumulates remaining unproduced bypass thin oil columns reservoirs within the field. Horizontal well is recognized in rejuvenating these thin oil columns and since the oil column is thin at the top of reservoir with bottom water drive, the placement of the horizontal section near top of the reservoir is the key in avoiding early water break through, minimizing attic oil and optimizing reserve recovery.

The team recognized the existing conventionally-steered horizontal wells with standard technology cannot guarantee the optimum placement near reservoir top due to existence of great subsurface challenges. The short-comings to be overcome are:Exiting from the reservoir resulting in low reservoir contact, low drainage area and low recovery factor;Inability to maintain distance to reservoir top resulting in bypassed oil, early water break through and low recovery factor.

In this paper, technical assessment and filtration by the team enrooting to the successful selection and implementation of advance Well Placement Distance-to-Boundary technology to overcome the challenges will be highlighted. Subsequently total of 25 and 19 horizontal wells had been completed in 2008 and 2009 successfully and placed within 0.5 m below the verge of reservoir top without exit, keeping the well away from OWC. The success is registered with better Productivity Index based on well performance test done and the wells have been producing more than 90% oil whilst five times increase in production observed since put into production. This application had put the horizontal well in the optimal position possible for draining. Hence, oil incremental and longer production sustainability can be achieved and it has enabled horizontal wells to be economically developed in a thin oil-bearing zone in Lu Liang field and other similar fields in China.
Production Monitoring and Surveillance of ESP Wells—Maximizing Production and Recovery in a Volatile Economic Environment
Authors: Salim Muzahidin M. , Saenz Dan , Jadid Maharon , Rafea Mahmoud Abdel
Published: July 2010

The satisfaction of completing a workover project and handing wells back to operations is just the beginning. The ongoing surveillance and constant adjustments towards optimization will ultimately determine the success or failure of such an undertaking. This is particularly true with Electrical Submersible Pumps (ESPs).

In mid-2009, the first three production ESPs in Malaysia were commissioned and started offshore Sarawak in the Bokor Field. These were a step change in field operations as all other wells are produced primarily via gas lift. A great deal of planning and preparation was required to analyze well output against baseline calculations, test each well thoroughly to monitor for water breakthrough or sand, and monitor the platform infrastructure to ensure the additional loads and production expected.

Online surveillance has played a key part in assisting the project team towards optimizing the wells and observing pump performance. The system as installed has allowed for remote frequency changes to adapt the pump for current conditions. Additionally, the surveillance system has been employed to protect the pump during unplanned shutdowns.

The production results thus far show that the ESPs are producing several hundred barrels oil greater than the gas lift baseline. Solids have not been an issue and the production GOR has been amongst the lowest in the field. However, the objective from the project execution plan is to continue increasing to 1700 bopd incremental. To achieve this, the project team will need to continue the workflows and processes developed to ensure a successful ending.
A Method to Quickly Estimate the Probable Value of Shale Gas Well
Authors: Dougherty Elmer L. , Chang Jincai
Published: July 2010

We give test results for the simple exponential model and the power-law exponential model for predicting shale gas production. Three parameter estimation methods tested show that analytical procedures are far superior to derivative methods. Economic evaluation tests show that economic factors may be more important than the details of the forecasting model used.
Catalytic Properties of Clay Based Hybrid Materials for Drilling Operations
Authors: Lee Jung-Kun , Son You-Hwan , Tran Phuoc , Soong Yee , Martello Donald , Chyu Minking
Published: July 2010

Iron-clay nanohybrid particles which are comprised of clay matrix and embedded rod-like iron nanoparticles have been succesfully prepared via intercalative route, and their magnetic property and caltalytic efficacy have been verified using magnetometer measerment and Fenton reaction.
Environmental Regulations, Technology, and Cost of Compliance for Oil & Gas Operations
Authors: Rana S..
Published: July 2010

The purpose of the paper is to emphasize the balance between cost of extraction & production (E&P) operations and complying environmental regulations to gain a better understanding of reducing overall costs associated with today’s oil and gas production while discussing importance of relevant technological innovations.

Due to recent coherent global initiatives on environmentally safe energy production and use, it has become increasingly important that the industry constantly search & implement a practical balance between environmental regulations and use of best available technologies with objectives of cost savings, not only to comply with the regulations but also to keep the operations sustainable for both small and large companies. The industry nearly spends as much on environmental protection as it spends searching for new domestic supplies of oil and gas; roughly 9 cents per gallon of gasoline (U.S. Department of Energy), amounting to over $10 billion a year. The cost of compliance with environmental regulations places a substantial economic burden on industry.

With this perspective, some specific conclusions and successful cost reduction technologies are listed along with general compliance items and costs data for each item (e.g., inspections and testing for drip & leaks, corrosion, costs incurred to safely dispose wastewater, etc).

The paper further highlights cost factors based on surveys/industry data, including situations when full implementation of latest E&P technology was lacking. As an example, in recent past, producers spent more than $3 billion per year in the US to comply with environmental regulations only. For some, combined estimated costs sustained an overwhelming net loss of about $4 to $5 per barrel (including roughly 20% cost of compliance) making very difficult to sustain E&P operations. Therefore, paper discusses the importance of balance between costs of overall operations and environmental compliance in most practical ways to benefit both small and large companies.
The Ejector Technology in Oued Zar Plant
Authors: Abdelli H..
Published: July 2010

The Oued Zar process is continuously progressing and growing. In fact, the exploitation of the new well reserves engendered an important increase of the quantities of oil and gas to be treated. One of the major issues associated to this evolution was to optimise the process and to consider environmental impact. The purpose of this work consists on the application of the ejector technology in real case.

The ejector is a pump-like device that uses the Venturi effect of a converging-diverging nozzle. It converts the pressure energy of a driver fluid to velocity energy. A low pressure zone is created and entrains a suction fluid. After passing through the throat of the injector, the mixed fluid expands and the velocity is reduced, thus recompressing the mixed fluids by converting velocity energy back into pressure energy.

ENI Tunisia had previous experience using the ejector technology in Oued Zar plant. The Ejector design is specific. It’s intended to suit an individual case requirement for maximum operating efficiency. Thus, for the conceptual phase, first step of the project, real field data (the gas outgoing of separator and the driver gas characteristics) are required. This information is obtained by CPG analyses and pressure measurement. Then, the performance of ejector is evaluated for different drive flow. The second step consists on field installation. The ejector started up in December 2006. The excellent results obtained during the test were confirmed. The ejector is still working with high performance and very low maintenance cost.

This experience confirms the first field installation of ejector was successfully accomplished in the Oued Zar oilfield in 2006 and encourages using it for other similar projects.
Profile Modification in Injection Wells Through Relative Permeability Modifiers: Laboratory Validation and Reservoir Simulation
Authors: Vasquez Julio , Miranda Carlos
Published: July 2010

Waterflooding is a well-established technique in the oil industry to improve hydrocarbon recovery in a given reservoir. However, in the absence of profile modification, water injected into the reservoir will go into the high-permeability zones and will bypass the oil-saturated, low-permeability zones. This paper presents the laboratory validation and reservoir simulation of a relative permeability modifier (RPM) used for profile-modification improvement in injection wells. By injecting the RPM within the high-permeability zones, subsequent injected water will be diverted into low-permeability zones to improve the sweep efficiency of the waterflooding project.

This RPM is a water-soluble relative permeability modifier initially developed for water control in production wells. The polymer functions by adsorption onto rock surfaces and effectively reduces water flow with little or no damage to hydrocarbon flow. These treatments are extremely easy to mix and pump, and require no post-job shut-in time. This RPM was evaluated in 5- and 10-ft sandpacks to investigate parameters, such as depth of penetration, diversion properties, treatment injection rate, and polymer concentration. Laboratory results indicate this RPM can effectively penetrate through a 10-ft sandpack, providing permeability reduction to water throughout the length of the porous media. In addition, excellent diverting properties were observed while bullheading the treatment in sandpacks in parallel with significant permeability contrast.

In addition, a 3-D numerical simulator was used to evaluate the performance of the RPM system under different scenarios and varying parameters, such as (1) permeability contrast between injection zones, (2) presence/absence of shale barriers between injection zones, and (3) treatment volumes, among others. This paper presents the results of these simulations and the impact it has on hydrocarbon and water production and the overall profitability of a particular field. In addition, the field implementation of this technology in injection wells is presented.
Best Practices for Candidate Selection, Design and Evaluation of Hydraulic Fracture Treatments
Authors: Martin A. N. , Economides Michael J.
Published: July 2010

Hydraulic fracturing is a well-established completion technique, most notably in the tight and unconventional gas reservoirs of North America. Although still not nearly as prevalent, fracturing is the completion method of choice throughout the world, providing unparalleled contact between the reservoir and the wellbore. Placing a fracture means that it takes less energy to move the oil or gas from the reservoir to the wellbore. Flow rates are increased dramatically and reservoirs can be depleted to significantly lower pressures prior to abandonment. The process is accomplished by physically breaking the formation apart with extreme pressure and then placing a highly conductive and crush-resistant material ("proppant") inside the fracture. Subsequently, oil and gas will flow through the "propped" fracture and into the wellbore. Because the propping material has a permeability that is orders of magnitude greater than the formation, virtually all flow passes from the reservoir into the fracture and then along the fracture into the well. The hydraulic fracture length can reach significant distances into the formation, providing the inflow area that is essential to the production of gas from tight and unconventional formations, although remarkable results can also be achieved from medium- and high-permeability reservoirs.

Although fracturing is often perceived as a technique for low-permeability reservoirs or remediation of mature fields, the best results are achieved from the best wells. One 100-md oil reservoir, effectively fractured, will produce the equivalent of 20 to 30 massive fracture treatments in 1-md reservoirs - and this factor increases to 50 to 70 for gas wells, due to the mitigation of turbulence within the reservoir.

This paper is concerned with the processes of candidate selection, treatment design and treatment evaluation, and in particular with the best practices that help optimise these procedures, including measurements that make fracturing more successful, wellbore design, treatment design techniques and materials selection. Finally, the paper will consider how these processes may subsequently evolve.
Novel Approach to Mitigate Gas Production in a High GOR Carbonate Reservoir With Drilled Wells—Case Study
Authors: Chekani Mitra , Bagherpour M H. , Alavi M.. , Kharrat Riyaz
Published: July 2010

Improving oil production is one of the most challenging subjects in carbonate reservoirs, especially in the case of thin formations when reservoir pressure is close to saturation pressure with undesired well locations. In this study water injection was used to mitigate gas production in a thin reservoir with high gas oil ratio for the purpose of optimizing oil production.

The studied field is a cretaceous oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150md and 5-35 percent respectively. The oil gravity is 21.5 degree API and reservoir pressure of 1700psia which is close to bubble point pressure of 1492psia. The produced wells were drilled in top layers of the reservoir.

A full field model was constructed to determine the optimal production strategy and applied reservoir management with available produced well locations. Two possible scenarios; namely, natural depletion and water injection were compared. Results indicated that water injection yields better recoveries than natural depletion. Different scenarios of injection well location, well orientation and mechanism of injection were considered.

Horizontal injection and production wells located at same layer were found to maintain reservoir pressure, prevent gas production, and increase oil recovery. Depleted regions near the producers were found to play a major rule on the success of the project. The enhancement of oil recovery was improved to 37 percent in the case of water injection with the implementation of proper reservoir management.
Production Enhancement Through Integrated Asset Modeling Optimization
Authors: Couët B.. , Djikpesse H.. , Tonkin T.. , Wilkinson D..
Published: July 2010

Gas lift optimization is often used to enhance production of mature oilfields consisting of multiple reservoirs. For increased efficiency, several of those reservoirs often share the same surface processing facilities. In such context, we wish to find the optimal allocation of gas lift over an entire network of wells and pipelines, while accounting for the constraints imposed by the reservoir operating conditions. The latter may include a limited amount of commodities that can be processed or a limited amount of available lift gas per unit of time.

Such engineering optimization problems are extremely difficult to model and to solve efficiently because they involve non-smooth models and are subject to constraints that might be simulation-based and as costly to compute as the objective function. Traditionally, they are solved using either penalty methods, which aggregate objective functions and all constraint evaluations, or classical lexicographic ordering, which evaluates all constraints simultaneously. While those techniques might be appropriate for computationally simple constraints, they could exhibit inefficiency when evaluating simulation-based constraints like the ones encountered in production optimization.

In this modeling study, we describe a cost-effective approach to perform such optimizations. An adaptive proxy is used to replace the original constraints and objective function calculation, and a novel sequential lexicographic ordering approach is used to handle the constraints: the linear constraints take precedence over nonlinear constraints and simple nonlinear constraints take precedence over simulated-based ones, which, in turn, take precedence over objective function values. The proxy is periodically validated against the original function to maintain consistency. The methodology and two oilfield-production optimization examples involving oil and gas separation are described. These serve to demonstrate that the proposed method is more efficient than the traditional ones.
Combining and Customizing Technologies for Perforating Horizontal Wells in Algeria
Authors: Addoun Mohammed , Chisholm Ken , Ottolia Davide , Gama Cesar , Cosentino Renato , Dozoul David , Annibaldi Alessandro
Published: July 2010

Alternatives for perforating a horizontal well to maximize well potential vary according to equipment availability and requirements. In a rigless operation in Algeria, the combination of orienting the perforations upwards and shooting multiple small intervals instead of the whole horizontal section while maintaining an accurate depth control was the biggest operational challenge of the project. The final design customized new technologies, including dynamic underbalance perforation, addressable switches, and the use of premium deep-penetrating shaped charges. The results were satisfactory, and the well, which was perforated in two stages, currently produces 2,000 m3/day crude oil from both the toe and heel sections.

Execution of the rigless, electric-line-equipped coiled tubing perforation in the horizontal well included aligning the charges to the upper side of the horizontal section to avoid salting and to prevent gun debris from falling down into the well, maintaining the debris inside the gun carrier. Several laminated sections out of the 600-m total horizontal section were selected, and accurate depth measurement and correlation were necessary to perforate only the cleanest 200 m.

This paper provides the operational sequence and discusses alternative conveyance methods available in the industry.
Scale Buildup, its Detection and Removal in High Temperature Gas Wells of Miano Field
Authors: Shar Amjad Hussain , Ahmad Tofeeq , Bregar Udo B
Published: July 2010

Scale deposition, either in the formation, well bore or in the production facilities is a challenging problem in the petroleum industry.

Scale problems are generally associated with the deposition of inorganic minerals, such as calcium carbonate (CaCO3) and sulfates of calcium, strontium and barium. Downhole mineral scaling is either a product of self-scaling of the formation water (FW), (carbonate scale associated with changes in pressure and/or pH) or the mixing of incompatible waters (FW and injection water) with elements of other wellbore fluids or other minerals. The cost of scale buildup can be high, both in terms of deferred production and necessary remedial treatments.

Depending on the nature of the scale and the fluid composition, the deposition can take place within the reservoir, near the wellbore perforation tunnels which causes formation damage, or in production facilities subsurface and on surface with severe operational problems.

The Cased Hole Gamma Ray measurement has been proven quite effective to detect the presence of scale, due to radioactive content proven by the Scale XEM/EDAC analysis. The Scale solubility analysis has proven more than 95% of the sample, are soluble in 10%-HCl based acid.

Finally, the two case studies of Miano field have brought a new game changer for operations, to enhance the gas production. It is based on historical well observation, since no water production had been observed at the surface in one of the case study, so Scale was not considered to cause the production decline. Therefore the method of Cased Hole Gamma Ray measurement can be in some cases the only indication of scale build-up if other indicators are missing. Furthermore it’s also an effective method to prove scale build-up inside perforations if hole is fully accessible.

This paper describes the buildup of scale, its detection and its successful removal with coiled tubing in high temperature gas wells of Miano Field. Furthermore it will show some lab results, the execution and evaluation the results of a successful operation, which resulted in a restoration of high productivity.
Maximizing Well Life and Optimizing Exploitation Strategies With Solid Expandable Tubulars
Authors: Contreras Jesus D. , Durst Doug , Al-Qaissy Ammar
Published: July 2010

Workover operations are a fact of well maintenance that can range from a simple intervention to a costly remediation. Common global issues that warrant workover operations include correcting production or injection profile issues, converting wells from producer to injectors (or vice versa), correcting cementation problems, mitigating corroded casing, fracturing or re-fracturing zones, changing artificial lift methods, and perforating or re-perforating new or existing zones.

Taking into account the wells’ lifespan is decades long, well integrity is often compromised as flow of fluid conditions cause erosion and corrosion problems. This compromise in well integrity requires a workover strategy that maximizes the well’s life cycle. Solid expandable tubular systems are a proven technology that facilitates these types of strategies. Additionally, solid expandable systems support other enabling technologies and techniques such as smart completions, multi-fracturing strategies, steam-assisted gravity drainage (SAGD) applications, and unconventional enhanced oil recovery (EOR) strategies.

This paper explains how an operator with existing wells in northwest Texas conducted a workover program converting gas producers to CO2 injections. Because the oil in place had the potential to equal that of the remaining oil in the reservoir, the optimal approach would require a solution that prevented sacrificing hole size. Solid expandable tubular systems installed in more than 25 wells isolated the existing upper perforations and enabled injection through newly-perforated lower oil intervals.

CO2 injection remains an important EOR method in the US in spite of oil price swings and ownership realignments. This is especially true in the Permian Basin of West Texas and New Mexico. Over 95% of the CO2 flooding activity is in the United States, mainly in the mature Permian Basin of the southwestern U.S., and dominated by injection under miscible conditions. (Kulkarni et al, 2008) There are 1,673 reservoirs in the onshore lower 48 United States which are candidates for CO2 miscible flooding. These reservoirs were identified using the following criteria: (Kulkarni et al, 2008)API Gravity greater than 22 degrees.The reservoir pressure greater than the minimum miscibility pressure.Depth greater than 2,500 ft.Oil viscosity less than 10 cp.Current oil saturation is greater than 20% of the pore volume.Either sandstone or carbonate rock.

This paper discusses operational procedures to explain the workover strategy and its relationship with the exploitation strategy – which was to optimize final recovery of reserves and maximize the life cycle of existing assets.
Polymer Compositions for Sand Consolidation in Oil Wells
Authors: Lahalih S. M. , Ghloum E. F.
Published: July 2010

Several polymer formulations were prepared and they have been characterized for their physical and chemical properties with viscosities ranging from 14 cP to 418 cP for concentrated solutions and from 3.5 cP to 15.8 cP for diluted solutions when measured at 80°C. Several polymer formulations met the critical test of stability when sand cores were immersed in 3% KCl brine stored at 80°C for over 1000 hrs. Also several formulations gave very significant improvement in the compressive strength of the treated sands that exceeded the minimum compressive strength of 10 Kg/cm2 by a factor of two to three. The safe compressive strength of oil producing well formation is reported to be about 10 kg/cm2 in order to have a stable formation that sustains shear bands. These polymeric compositions were also tested on Kuwait dune sands and actual oil well formation sand of Minagish oil well MN-117 in Kuwait. Results show that compressive strength values of three to several folds of the recommended values for oil formation were realized. Values of 35-100 kg/cm2 were achieved from this work. Improving compressive strength of weak and friable formation is one of the three main requirements for a successful sand consolidation treatment. Core flooding test on sandpacks made from dune sand and Minagish well MN-117 sand show that all polymer compositions developed compressive strengths in the treated sandpacks that far exceeded the minimum requirement of 10 Kg/cm2 and gave complete water shutoff to water production. Finally higher temperatures required higher doses of these compositions where 1.0 PV, 0.4 PV and 0.25 PV of these polymers were needed to produce the desired compressive strength at 110°C, 80°C and 60°C respectively.
Combining the Use of ESPs and Distributed Temperature Sensors to Determine Layer Water Cut, PI, and Reservoir Pressure
Authors: Camilleri L. A. , Akram A. H. , Quinzo Bravo M. E.
Published: July 2010

In many oil wells, production is commingled from several layers. In such environments, understanding the properties of individual layers is essential to reservoir surveillance and production optimization. The inflow properties that typically require measuring are productivity index (PI), water cut, and static reservoir pressure. These measurements have traditionally been taken with wireline-conveyed production logging tools (PLT); however, in many wells and operating environments, completion and logistic considerations make running these tools difficult or even impossible. In those instances, an alternative is required. This paper presents a new procedure based on multirate testing in combination with distributed temperature sensors (DTS), an electric submersible pump (ESP) fitted with a gauge in the commingled fluid stream, and conventional surface testing. The additional test rates provide sufficient equations to resolve all the unknowns, whereas the DTS provides essential information such as which layers are producing and which are taking fluid, as well as a mass flowrate tool for measuring the flow rate of each layer. The procedure requires varying well flow rates over a range sufficient to ensure that all layers are producing, which in many cases requires an ESP to provide sufficient drawdown to overcome crossflow as well as a variable-speed drive to establish the test rates. The theoretical basis for the protocol is described, and an example is detailed to demonstrate the validity and robustness of the method for determining inflow properties. Finally, theoretical and practical guidelines are provided to demonstrate how the test procedure is affected by fiber-optic resolution, fluid properties, and the geothermal gradient. For wells equipped with forms of artificial lift such as ESPs, beam pumps, and progressive cavity pumps (PCPs), running PLTs is often not possible because of the completion obstruction. In such cases, this new DTS-enabled procedure has the potential of becoming the PLT substitute of the future.