bluuebunny/crossref_metadata_2025 huggingface dataset:
Deepwater Horizontal Openhole Gravel Packing in Marlim Sul Field, Campos Basin, Brazil—Completion Project Learning Curve and Optimization
Authors: Acosta M. , Farias R. , Vilela Á. , Mendez A. , Pineda F. , Montanha R. , Garcia E. , Calderon A. , Magno C. , Germino M.
Published: December 2007

Most of deepwater Campos Basin reservoirs, offshore Brazil, have unconsolidated formations that require sand control. Openhole gravel packing has proven to be the effective completion method of choice. The main objectives were to achieve low damage ratios, maximize completion efficiencies and reduce completion cycle times.

The project was conducted in one of the largest deepwater offshore field in Brazil, Marlim Sul. This paper describes the learning curve and completion optimization obtained during planning, execution, and post job analysis of six horizontal wells campaign with five water injectors and one oil producer.

A combination of integrated service lines and experienced personnel were important to achieve excellent injectivity and productivity ratios. Several key operations from drilling to completion contributed to successfully complete these wells: openhole stability, drilling practices, drill-in fluids, wellbore clean-up, filtration, completion fluids, completion tools, sand control, gravel pack software simulator and job execution.

The efficiency of the service company was measured with a system of penalties and rewards allowing the operator to monitor and measure the progress of the learning curve on completion. As final result, the partnership between operator and service companies contributed to more economic completion costs by reducing completion time, and improving well performance.
Fracturing-Fluid Crosslinking at Low Polymer Concentration
Authors: Lie C. , Clark P. E.
Published: December 2007

Proposal

Crosslinking water-soluble fracturing fluids has been one of the most cost effective technologies developed for hydraulic fracturing. It has allowed these fluids to be used in hostile conditions that would have otherwise required impossibly high polymer concentrations. A great deal of work has been done on crosslinking chemistry and crosslinked fluid rheology and this has led to a better understanding of these fluids. Higher prices for hydrocarbons have taken exploration into more difficult areas and increased the importance of production from existing fields, both of which will require better technologies to economically exploit these reserves. This means that new efforts need to be focused on fracturing fluid improvements

Low polymer concentration crosslinked systems have proven to be extremely effective for both initial and restimulation. The first of these fluid systems were based on zirconium crosslinked carboxymethyl guar. These fluids were effective at transporting proppant and, because of the low polymer concentration, provided low levels of formation damage and quick clean-up. In order to develop the next generation of cost-effective fracturing fluids, a better understanding of the controlling mechanisms for low-polymer concentration crosslinking must be developed.

This paper will describe techniques for characterizing the crosslinking process and crosslinked fluids that will be needed to develop this next generation fluid. We will clearly demonstrate the relationship between the critical crosslinking concentration (minimum polymer concentration where the fluid is crosslinked) and the critical overlap concentration (the minimum concentration for polymer-polymer interaction). In addition, this paper will demonstrate the relationship between crosslinking agent and polymer type to crosslinked gel properties. Most water-soluble polymers exhibit two transitions in the viscosity-concentration curve. The first is the critical overlap concentration and the second is generally recognized as the transition from semi-dilute to concentrated. Concentrations necessary to produce a useful low-polymer concentration crosslinked system are generally between these two transitions and above the critical crosslinking concentration. The useful concentration depends strongly on the polymer and not as much on the crosslinker. All of this information will be used to provide guidelines for the development of future crosslinked systems.
Combining Small Well Spacing With Polymer Flooding To Improve Oil Recovery of Marginal Reservoirs
Authors: Wang J. , Wang D. , Sui X. , Zeng H. , Bai W.
Published: December 2007

Because of low volumetric sweep efficiency and large difference in injection and production rate of each zone, the recovery factor of water flooding is very low in some continental and heterogeneous sandstone oil fields, especially when the reservoir continuity is poor, permeability low and high permeability variation between different zones. Due to the amount of incremental producible oil is not large enough to further drill infill wells economically, drilling infill wells and performing polymer flooding simultaneously was proposed and a pilot test has been concluded.

The paper introduces the laboratory studies on selection of polymer injection parameters and project design optimization. According to these studies, a pilot test of "Combining Small Well Spacing with Polymer Flooding" was conducted. The well spacing is 100 meters, the zones with a thickness of less than 1 meter and with a permeability rage of 5 to 100 md were combined together and put on development. Both lab studies and pilot results show that the volumetric sweep efficiency was greatly increased, especially after applying separate zone injection measures in polymer injectors based on injection profile surveys and tracer test data. The pilot test indicates that the technique of combining infill wells with polymer flooding is economically feasible with 10% OOIP incremental recovery at a production cost of $10/bbl.
Steam-Injection Experiments for Recovery of Heavy Crude Oil of an Iranian Field
Authors: Tabatabaei-Nejad S. A. R. , Shafiei S. , Rajabzadeh S. , Haghlesan A.
Published: December 2007

Thermal methods for enhanced oil recovery account for the large share of the world's production. Steam flooding is one of the oldest commercial methods to enhance the heavy oil recovery. In due respects, experiments of steam injection into a sand pack were performed to study the recovery of heavy oil (API<20) and a lighter oil (API>20) of Iranian field. Two different porosity of sand pack were used and the experiments were conducted with four different types of heavy oil, with different API, to study their effect on recovery. An experimental setup was designed and used to inject the steam into the sand pack. Using different pressures at each experimental run, results show that there is an optimum pressure, which is the characteristic of each reservoir and must be determined by field experiments. The rate of injected steam has an important effect on recovery and an optimum rate exists for ultimate recovery. Steam injection is more effective for heavy oil reservoirs, as for light oil reservoirs; there is the risk of fingering which results in production of steam without sufficient oil production. Even though, in literature, some authors have indicated that the steam injection could be used for the lighter oil reservoirs (API~ 24 or more) but based on the conducted experiments it is proposed to take more care.
A Numerical Technique for Simulating Nonplanar Evolution of Hydraulic Fractures
Authors: Rungamornrat J. , Wheeler M. F. , Mear M. E.
Published: December 2007

A computational technique has been developed for simulating non-planar evolution of hydraulic fractures in three-dimensional elastic media. The technique utilizes a symmetric Galerkin boundary element method to treat the elasticity problem associated with a fracture in an unbounded domain, and a Galerkin finite element method to model the (non-Newtonian) fluid flow within the fracture. The boundary element method is based upon a weakly-singular, weak-form traction boundary integral equation which is applicable to nonplanar fractures in generally anisotropic media. Since the integral equation is only weakly-singular, standard C° elements can be employed, and such elements are adopted everywhere except along the fracture front where a special crack-tip element is used. The fluid flow within the (non-planar) fracture is described in terms of a "channel flow relation" cast in a weak form well-suited for numerical treatment. The final system of non-linear algebraic equations (for the relative crack-face displacement and fluid pressure) is then solved using the Newton-Raphson method. To illustrate the capabilities of the method, example simulations are presented including ones involving complex non-planar crack growth.
Matrix Selection for Conventional and Nonconventional Testing and Sampling in Gas Reservoirs
Authors: Adeyemi O. S. , Edwards M. D.
Published: December 2007

A selection matrix, suitable for discriminating between different techniques for testing and sampling gas reservoirs is presented. The paper provides a quick guide for selecting appropriate sampling/testing methods based on the desired objectives while incorporating operational efficiency, safety/environmental considerations and cost implications. This selection is guided by determining the optimal technique/tool to be e ngaged for obtaining dynamic reservoir properties and uncontaminated gas samples. Thi s can be a great challenge depending on the available technology, reservoir/fluid properties, mud type and economic considerations. The aim is to select a n optimal tool/technology that will meet th e desired objectives without compromising safety and still be cost effective.

This paper is intended to provide a methodology for selecting applicable technology for char acterizing sweet gas (dry/wet) reservoirs, especially during the e xploratory or appraisa l stage. The uncertainties during this stag e make justification for a comprehensive formation evaluation quite difficult due t o high cost or operational concerns.

The paper shows that combining this selection matrix with value of information (VOI) and cost benefit analysis (CBA) will significantly assist project teams in establishing an optimum sampling and testin g program that is f it for purpose. This methodology may result in si gnificant operational savings, especially in high cost environments
First-Time Application in Mexico's Burgos Basin of a New Technology Multistage Completion Process: A Successful Case History
Authors: Centurion S. , Valenzuela A.
Published: December 2007

The Burgos Basin, located in Northern Mexico, is considered by PEMEX to be one of Mexico's major natural gas reserves, and contributes a large portion of the country's current gas production. The basin's gas production comes from a series of sandstone intervals, which are primarily characterized as very low permeability. Consequently, the only way to obtain optimum production rates is using hydraulic fracturing techniques.

Given that all the wells of the basin offer multiple potential productive zones, PEMEX was driven to look for alternative methods and technologies, focusing their efforts on finding the most cost effective completion processes while maximizing the production and returns in the field development.

For years, the conventional completion process used by PEMEX has been PFFP ( perforate-fracturing-flowing-plugging), then moving up hole to the next interval and repeating the process. This process was strongly debated internally for quite some time due to considerable concerns of formation damage caused by fracturing fluids remaining in formation for extended periods of time prior to being recovered. Thus the focus became to modify and optimize each step of PFFP in order to reduce these concerns and their impact on the well's production.

In 2003, a fairly new technology in multi-stage treatment completion process was used. This technique, known as "External Casing Perforating" allowed PEMEX to perforate and isolate individual zones in as little as minutes between stages. As many as 5 zones have been completed within a 30 hour period. The time from completion to production has been reduced from days to hours.

This paper will describe the implementation of this technique in the Cuitlahuac Field, Burgos basin. Most importantly, the case history is substantiated by a comparison with offset wells. The analysis includes the completion processes used, early and normalized gas production and an economical analysis made using both the conventional and the multi-stage processes. In conclusion, the Production Company's perspective about implementing this technology in a massive operation will also be presented.
Fracture-Matrix Transport Dominated by Capillary-Driven Flow in Layered Sandstone
Authors: Karpyn Z. T. , Halleck P. M. , Grader A. S.
Published: December 2007

Fluid transport in reservoir formations under quasi-static conditions is strongly dominated by capillary forces. These forces are a macroscopic manifestation of complex molecular interactions between fluids and solids inside the intricate pore structure of rocks. In naturally fractured reservoirs, spontaneous capillary imbibition is an important recovery mechanism since waterflooding of the disjointed matrix cannot be accomplished by forced displacement.

The goal of the present experimental work is to establish a detailed reference case for the validation of numerical models of capillary-driven flow in fractured formations. This paper presents experimental results of two-phase capillary-driven flow in a layered Berea sandstone sample with a single longitudinal fracture. The sample was artificially fractured using a modified Brazilian test that resulted in an extensional longitudinal fracture oriented perpendicularly to the natural bedding planes of the rock. Non-destructive high-resolution X-ray CT imaging allowed identification of localized cocurrent and countercurrent flow during spontaneous capillary imbibition.

Three distinctive flow intervals were identified during spontaneous imbibition. Those are early, intermediate, and late time. The presence of bedding planes in the rock's structure determines the shape of the imbibing front during early-time imbibition. The imbibing front advances faster through low porosity/permeability layers due to higher capillary forces. Cross-layer fluid exchange tends to level the imbibing front during the intermediate imbibition stage. Countercurrent flow controls fluid transport during the early and intermediate intervals, while both cocurrent and countercurrent flow mechanisms coexist at late time. Results from this experimental work present strong evidence of localized hysteretic behavior. Drainage, imbibition, and transition zones characteristic of countercurrent flow are clearly identified as a function of time.
After-Closure Analysis for Naturally Fractured Reservoirs: Field Examples
Authors: Chipperfield S.
Published: December 2007

Economic optimization of fracture stimulation designs requires accurate reservoir description (ie. permeability and permeability thickness) and an understanding of the deliverability mechanism (ie. natural fractures versus conventional matrix). This paper presents a technique which allows an engineer to evaluate a mini-frac injection in a similar manner to a conventional pressure transient test for the identification of productive natural fractures. Following a brief theoretical background to this new methodology, this paper provides a field validation study in oil and gas fields on two continents.

Identifying natural fractures drives certain changes in stimulation design. Techniques designed specifically to stimulate natural fractures include low gel loadings, energized fluids and 100 mesh sand for natural fracture preservation1,2.

A recently published mini-frac evaluation technique using the After-Closure pressure information3 provides a methodology which can identify productive natural fractures. Using this methodology, this paper delivers a retrospective evaluation of mini-frac information using data from tight gas fields in Central Australia and an oil field in Algeria. In addition, the results are validated with independent constraints such as pre-closure mini-frac analysis, conventional well testing, image logs and core analysis.

Finally, the results of this evaluation are distilled into a simple field implementation methodology which can be incorporated into a conventional pre-frac injection sequence.
Condensate Skin Evaluation of Gas/Condensate Wells by Pressure-Transient Analysis
Authors: Shandrygin A. , Rudenko D.
Published: December 2007

Condensate blockage of gas-condensate wells is widely recognized as an important problem. In dry-gas wells, zone damage (blockage) is typically quantified by skin factor, which is obtained by interpreting pressure-transient testing results. In gas-condensate wells, however, the complex behavior of gas-condensate fluid creates problems for application of commonly used interpretation methods for estimating condensate skin. This paper proposes a procedure for evaluating skin in gas-condensate wells, using a simplified numerical model. The proposed procedure is based on a single-phase approach, treating condensate as immobile, without phase transitions between gas and condensate. This reduces the number of input parameters and dramatically decreases computational cost. Radial condensate distribution is described using condensate-bank radius and maximum condensate saturation as regression parameters for fitting modeled build-up pressure curves with well-test data. Evaluated bank parameters provide an estimate of the skin caused by condensate blockage in the near-wellbore zone.

The procedure was validated for a radial reservoir. Synthetic well-test data generated using compositional simulator was used to conduct a sensitivity study for various production regimes and reservoir properties.

The proposed procedure provides a reasonable estimate for the condensate skin value. However, it has some limits of applicability like any other method not using compositional modeling to simulate gas-condensate flow in porous media.
Rock Typing as an Effective Tool for Permeability and Water-Saturation Modeling: A Case Study in a Clastic Reservoir in the Oriente Basin
Authors: Guo G. , Diaz M. A. , Paz F. , Smalley J. , Waninger E. A.
Published: December 2007

In clastic reservoirs in the Oriente basin, South America, rock-quality-index (RQI) and flow-zone-indicator (FZI) prove to be an effective technique for rock type classifications. It has long been recognized that excellent permeability-porosity relationships can be obtained once the conventional core data are grouped according to their rock types. Furthermore, it was observed from this study that the capillary pressure curves as well as relative permeability curves also show close relationships with the defined rock types in the basin. These results lead us to believe that if rock type is properly defined, a realistic permeability model, a unique set of relative permeability curves as well as a consistent J function can be developed for a given rock type. The procedure for implementing this technique in our reservoir modeling is described in the paragraphs below.

Conventional core data were first used to define the rock types for the cored intervals. The wireline log measurements at the cored depths were extracted, normalized, and subsequently analyzed together with the calculated rock types. A mathematical model was then built to predict the rock type in uncored intervals and in uncored wells. This allows the generation of a synthetic rock type log for all wells with modern log suites. Geostatistical techniques can then be used to populate the rock type throughout a reservoir.

After rock type and porosity are properly populated, the permeability can be estimated using the unique permeability-porosity relationship for a given rock type. The initial water saturation for a reservoir can subsequently be estimated using the corresponding rock type, porosity, and permeability models as well as the rock-type-based J functions. It was observed in our study that a global permeability multiplier became unnecessary in our reservoir simulation models when the permeability model is constructed using this technique. Consistent initial water saturation models (i.e., calculated and log measured water saturations are in excellent agreement) can be obtained when the proper J function is used for a given rock type. As a result, the uncertainty associated with volumetric calculations is greatly reduced as a more accurate initial water saturation model is used. The true dynamic characterisitcs (i.e., the flow capacity) of the reservoir are captured in the reservoir simulation model as a more reliable permeability model is used.
Evolution of Real-Time Operations Monitoring: From Concept to Global Implementation
Authors: van Oort E. , Rosso R. , Cabello-Montero J.
Published: December 2007

The unique challenges posed by deepwater wells of ever-increasing complexity continue to force operators and service companies to explore new and innovative well delivery solutions. In early 2002, Shell Exploration and Production Americas took an important step towards well performance optimization with the initiation of a pilot study into real-time, remote monitoring of exploration and production wells in the Gulf of Mexico (GoM). Starting with a small-scale "war room" concept with limited scope, the pilot quickly grew into the current New Orleans-based "Real-Time Operations Center" (RTOC), which monitors all offshore wells in the GoM as well as major exploration wells globally. Main objectives of this multidisciplinary collaboration center are to enable more pro-active well planning and improve well execution by reducing non-productive time (NPT) and invisible lost time (ILT). The success of the RTOC, as well as that of other independent well visualization and monitoring pilots in the Shell Group, has meanwhile led to significant steps towards global expansion and coverage.

In a follow-up to earlier papers1,2, we describe the current state-of-the-art in real-time operations monitoring technology deployment in the RTOC, and how it has evolved from the original pilot phase. We discuss the center's various activities, demonstrate how they add value and how this value is being measured. Key hurdles and success factors for implementation of an operations center are summarized. Moreover, the preliminary learnings from global deployment are shared.

The information may serve as a blueprint for the planning, design and operation of a real-time operations center both locally, regionally and globally. The expansion of real time engineering and monitoring services across the globe is a challenging and pioneering undertaking. Consequently, we hope that this paper will help to lead the way in expanding this capability in the oil and gas industry in general.
Use of DST for Effective Dynamic Appraisal: Case Studies From Deep Offshore West Africa and Associated Methodology
Authors: de la Combe J. L. B. , Akinwunmi O. , Dumay C. , Tachon M.
Published: December 2007

In the emerging West Africa deep offshore region, where exploration is booming, the turbiditic series reservoirs are mostly structurally trapped with a stratigraphic component. Faulting is severe inducing high compartmentalisation. Evaluation of connectivity and characterisation of the reservoir heterogeneities before development decisions are the main challenges.

These two long DST acquired at a relatively early stage of the appraisal were a game changer for the development project. Both demonstrated large scale reservoir continuity in a complex geological setting, which in turn provided extraconfidence on the feasibility of a large scale development project. The confrontation of this wide scale dynamic information to seismic data and geological concepts allowed significant optimisation of the remaining appraisal sequence.

Testing methodology, based on Total experience, advocates the setting of two cycles of draw-down and build-up to generate significant depletion between the two build-up's. This test sequence allows discriminating between geological models matching the derivative and assesses a minimum hydrocarbon connected volume.

The first case study concerns a third appraisal well drilled to recognise the turbiditic series of Late Miocene age in the Southern panel of a structure discovered recently. This test allowed us to prove a minimum oil connected volume of at least 120 MMbbls, much larger than the pre-test volume of 55 MMbbls estimated from seismic interpretation, and proved an extension of good reservoir facies beyond the seismic visibility limit.

In the second case study concerning an exploration well aiming to recognize the turbiditic sands of the same age, the shallower oil-bearing interval was tested. The fault density around the well being quite high, it was important to know if the faults would act as dynamic barriers. This test proved a minimum connected volume of around 90 MMbbls, and indicated that the encountered reservoir facies was developable as the high fault density around the location of the well did not negatively affect the dynamic performance. In this well, only one out of several faults at 130 meters from the well, within the investigated area of the test, acted as a dynamic barrier.
Production Management Information Challenges in the Digital Oilfield
Authors: DeVries S.
Published: December 2007

The Digital Oilfield needs to distribute information to personnel in many locations, companies and situations while satisfying requirements for privacy, protection of intellectual property, and suitability for new business processes. All of this must be accomplished with an appropriate set of standards. A key example is an escalating condition, such as a flow assurance problem, that requires the operating company to share information with one of several competing service companies. How does the access easily change based on the situation and supervisor decisions? How does a busy, remote, mobile expert know when to look at this information? How is this activity tracked? How does each organization protect their intellectual property? This transcends the domain of information technology and petroleum engineering expertise. This paper examines the three main challenges and proposes two new approaches to address them.
Unconventional RPM Applications in Hydraulic Fracturing
Authors: Leal J. , Gonzalez M. A. , Villa G. , Garay R. , Castro A.
Published: December 2007

In fracturing applications, addition of the Relative Permeability Modifiers (RPM's) to water base fracturing fluids, preferably to pre-pad and pad stages, can provide multiple potential treatment enhancement benefits. The RPM may reduce post-stimulation water production, and increase fracturing fluid efficiency. RPM's may also pump as a postfracturing treatment at matrix rates following load recovery. After the RPM treatment in an oil well, hydrocarbon solvents compatible with the hydrocarbon-bearing interval compose the recommended flush solutions. These solvents may include aromatic solvents such as xylene, diesel or mixtures of diesel and aromatic solvent. This flush is designed to reconnect the hydrocarbon reserves to the wellbore in an effort to accelerate return of oil production. In this application, the diesel base frac fluid accomplished this function.

In water sensitive hydrocarbon bearing is desirable to avoid excessive use of water base fluids. Good results are obtained using oil base fracturing fluids. However, RPM's cannot be added directly to oil base fluids. To address this issue, an unconventional method was proposed and executed with successful results. Prior to the propped frac treatment, a water base frac fluid with RPM polymer is pumped at fracturing rates, with a volume calculated to occupy the formation with an equivalent fracture geometry slightly larger than the expected created geometry of the subsequent propped oil/solvent based frac fluid treatment.

This paper describes guidelines for candidate selection for this application, analysis and logs to optimize treatments, advantages obtained with this method, and case histories in a Colombian field. The RPM used is a synthetic ter-polymer based on acrylamide chemistry.
Integration of Artificial Intelligence and Lean Sigma for Large-Field Production Optimization: Application to Kern River Field
Authors: Popa A. , Ramos R. , Cover A. , Popa C.
Published: December 2007

This paper represents an integration of artificial intelligence and lean sigma techniques to achieve large field production optimization. The first part of the methodology (detailed in SPE 90266 "Zonal Allocation and Increased Production Opportunities Using Data Mining in Kern River"1) involves data management and predictive data mining for increased production opportunity identification. It utilizes a set of data mining tools including clustering techniques and neural networks to identify new candidates for clean-outs, perforating, sidetracks, deepening, and other types of workovers. Furthermore, the expert system was used to predict the estimated production increase for these candidates. The second part of the methodology optimizes the implementation and post-workover follow up of the opportunities identified in part one. It involves the use of lean sigma tools such as value stream mapping, level loading, continuous flow production, standard operating procedures, and kanbans which optimize execution cycle time, peak oil production, decision making process, cost, and safety2. This approach was successfully applied and executed in the Kern River field.
Tougher Concrete Structures To Service and Protect Oil and Gas Operations
Authors: Moncarz P. D. , Krstulovic-Opara N.
Published: December 2007

Large on-shore and off-shore facilities for production, loading and unloading, and storage of petroleum products are being constructed with the use of reinforced concrete. Recent examples include the monumental platforms associated with the Sakhalin II development, and the development of new LNG facilities driven by the world demand for transportation of large quantities of natural gas over large distances. The political climate of the 21st century dictates a much higher attention level to questions of safety and security of these facilities. Terrorist threat requires not only a heightened surveillance and threat-response readiness, but also the incorporation of design features making such threats less likely to succeed. These design features include both structural and material level considerations. The authors discuss some of the currently available approaches to making concrete structures tougher to terrorist attacks while also making them more serviceable and longer lasting. Experience from research and field studies on fiber reinforced concrete, on slurry infiltrated mat concrete, and on Kevlar wrapping of critical concrete structure elements in high seismicity areas are some of the discussed topics. Suggestions are made how these examples could lead to toughening of oil and gas concrete facilities or of concrete protective barriers.
Risk and Uncertainty Management—Best Practices and Misapplications for Cost and Schedule Estimates
Authors: Peterson S. K. , De Wardt J. , Murtha J. A.
Published: December 2007

Risk management, risk analysis, and uncertainty analysis are still-growing trends in cost and schedule estimating. Engineers and managers alike have been lead to believe that correct application of best practices will ensure that operations achieve their objectives on time and within budget.

Unfortunately, a number of misapplications, misunderstandings, and mistakes have threatened to endanger the continued useful growth of this trend. Insufficient tools and / or incorrect use of the available tools have allowed creation of a false sense of security which is shattered by loss of objectives and time / cost overruns. It is very important that the industry understands and chooses the correct applications, and has realistic expectations.

This paper will present best practices for applying risk management, risk analysis and uncertainty analysis to capital expenditure cost and schedule estimates. In addition to outlining our recommended process, we will highlight current misapplications that, in our opinion, are potential barriers to the continued growth of this valuable management tool.
Effect of Operating Valve Performance on Stability of Gas Lift Wells
Authors: Fairuzov Y. V. , Guerrero-Sarabia I.
Published: December 2007

Heading (flow instability) is a common problem in the operation of continuous flow gas-lift wells. One of the key elements, which affect the gas-lift stability, is the operating valve. Several operating gas-lift valve designs are currently used in practice. A new valve design, based on the use of a supersonic nozzle ("the nozzle-Venturi gas-lift valve"), was recently proposed in the literature. In most cases, it is very difficult to estimate apriori (at the design stage) how the type of the gas-lift valve and its design parameters affect the stability of a gas-lift system to be operated at a given operating condition. In this paper, the effect of operating valve design on gas-lift stability was studied. It is shown that the gas-lift stability maps proposed in an earlier study may facilitate the selection of the operating valve design. Different valve designs were considered: the conventional orifice and gas-lift valves, as well as the nozzle-Venturi valve. Gas-lift stability maps were constructed for each operating valve design. Advantages and disadvantages of the considered valve types are discussed from the point of view of the gas-lift stability. Based on the comparison of the gas-lift stability maps, recommendations on the selection of the operation valve type were elaborated.
North Slope Heavy-Oil Sand-Control Strategy: Detailed Case Study of Sand Production Predictions and Field Measurements for Alaskan Heavy-Oil Multilateral Field Developments
Authors: Burton R. C. , Chin L. Y. , Davis E. R. , Enderlin M. , Fuh G. , Hodge R. , Ramos G. G. , VanDeVerg P. , Werner M. , Mathews W. L. , Petersen S.
Published: December 2007

The North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope’s vast heavy oil resource base. Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments.

The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel. With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production. Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis. These different methods for predicting solids production will be discussed and illustrated in this case study.

The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.
Case Histories: Post-Frac Fluid Recovery Improvements of Appalachian Basin Gas Reservoirs
Authors: Paktinat J. , Pinkhouse J. , Stoner W. P. , Williams C. , Carder G. A. , Penny G. S.
Published: December 2007

The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension of the fracturing fluid, decrease interfacial tension between injected fluid and reservoir rock and increase post-fracturing fluid recovery. However, many of these chemicals when injected at high pressures adsorb rapidly into the sandstone formation, reducing their effectiveness in post fracturing fluid recovery.

This study describes simulated laboratory experiments and case histories of various surfactants used in the oilfield. Several different surfactants including ethoxylated linear alcohol, nonyl phenol ethoxylate and a microemulsion system were investigated to determine their adsorption properties when injected into a sand packed column. A laboratory simulated comparison study of these surfactants versus a microemulsion system was used to identify their water recovery properties from gas wells.

Field data collected from Benson, Balltown, Injun, and Speechley Sandstone formations confirm experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional non-emulsifying surfactant treatments. Case histories reported from several gas wells stimulated in the Appalachian Basin illustrate the advantages microemulsions have over conventional surfactant treatments when faster cleanup, increased post fracturing fluid recovery and well productivity are of concern to the operator.
The Challenge Of Selecting Appropriate Drill String Enhancing Features For Drilling In The Middle East Harsh Environment
Authors: Plessis Guillaume , You Jean Bernard
Published: December 2007

Drilling in the Middle East is challenging and when it comes to drill string selection and design, the drilling engineer has to consider all the parameters that will influence the lifetime of the drill string, among which drilling environment, well geometry, need for drilling deeper wells in an always more economical manner.

As an example, on the environmental side, the presence of H2S in most fields doesn't allow using standard grades of material and could also require adding geometrical features to the string that allows regaining an acceptable lifetime, in conjunction with a control of the drilling fluid characteristics.

The well geometry and the necessity to tap oil in areas that could not be reached easily and are remote from the drilling site will require that the string has the ability to carry substantially higher loads and in particular allows transmitting high torques through the connection. This could be even more challenging when the operation requires that the tool joint diameter be limited to allow fishability.

Larger hole drilling dictates optimization of hydraulic in order to remove the cuttings efficiently and once again the geometry of the drill pipe is to be considered thoroughly. In this case, streamline connections with enlarged internal diameter can be provided without compromising on the torsional and tensile capacity of the drill string.

This paper aims at answering some of the drillers most commonly asked questions when designing drill strings, since it is essential to understand which parameter to play with in order to optimize the string design. We will expand, in particular, on the raw material selection, stress relief features, geometries and connections that allow increasing drilling performances, thus reducing the overall cost of the drilling operation.

Introduction

The objective of this paper is not to define one design that would be applicable across the region but rather to highlight specific conditions or requirements that could apply to drill stem products and the available solutions that allow drilling in an always more efficient and cost effective manner.

At first we will focus on the H2S embrittlement, which is one of the main concerns in this region.

Then we will concentrate on the general requirement for torque before finishing with a few examples of drilling efficiencies improvements that generally are the result of the use of the latest generation of streamlined double shoulder connections.
Application of Subsea O/W Separation: Main Drives and Challenges
Authors: de Figueiredo M. W.
Published: December 2007

Oil production is normally followed by water production in increasing rates, mostly when waterflooding is used as oil recovery mechanism. In order to minimize the impact that high rates of produced water causes to the topside facilities, Petrobras is working on the development of a subsea system for oil-water separation, so that most of the produced water can be separated on the mudline and reinjected in the reservoir or in a bearing formation. Besides the benefit of debottlenecking the production plant, there are gains in flowrate and flow assurance due to the less amount of water in the production stream.

The article also shows how this development has been carried on, the scenario definition for the pilot, the problems associated to an installation in a system already operating and the oil characteristics determination. These data constitute the base for the survey to detect the technologies with potential application on the separation system to be developed.

The special characteristic of the oil, with high tendency to form stable emulsions with water, are also analyzed, as well as the difficulties it brings to the process in the subsea environment, where there are vessel size and fluid heating limitations.
The Exploitation of Heavy Oil From Middle-Deep Reservoirs: Horizontal Well Completions at the Oritupano-Leona Field In the Eastern Venezuela Basin
Authors: Riera L. , Castillo J. , Bellorin W.
Published: December 2007

Since Petrobras Energía Venezuela took over the Oritupano-Leona Unit by agreement with PDVSA in March 1994, turned out a great challenge for the company about how to increase and improve not only the field potential but the reserves enhancement too. Low to high liquid rates horizontal wells were implemented in order to defeat one of the most challenging issues at the company: The exploitation of heavy oil from middle-deep reservoirs.

Numerical simulations along with geological studies were conducted to define the best strategy for performing new horizontal wells. Drilling and completions started five years ago making the first steps to get a technical and economical performance for well productions and at last, three stages were done. Stage I considered low liquid rates horizontal well completions ranging from 1,500 BFPD through 4,000 BFPD. Stage II was a little bit aggressive increasing rates from 7,000 BFPD through 10,000 BFPD and finally we went Stage III, where our goal was to reach more than 20,000 BFPD.

All cases observed that transient flow regime where water conning threats have to be faced before reaching semi steady state flow, lasts between 8 to 10 months. During these periods, different productions strategies were implemented.

Looking at adverse factors such as oil gravity ranging from 8 API to 12 API, reservoir depths from 7,500 feet to 9,000 feet, scales precipitation possibilities and a very strong aquifer presence with similar physical-chemical properties throughout the geological column, let anybody to think that it was obvious that obtaining these 20,000 BFPD, not reaching water conning effects, represented a very risky feat for the company.

The R sands in the Oritupano C field, one of the most productive blocks at the main Oritupano-Leona System, became as a remarkable experience after the nation wide largest horizontal well completion (Hz-13) with more than 20,000 BFPD; 12 API; 800,000bls cumulated oil and no water conning effects in the last 10 months. Some other areas are giving same results such as TU sand in the Oritupano B field.

Results show that improve oil recovery (IOR) from middle-deep horizontal wells in Eastern Venezuela have boosted the heavy oil production with no steamflooding and diluent injection techniques. Yet there are some issues to face such as emulsion formation in the early production during transient flow and the reservoir fingering or channeling effects that might prevent a second line of well construction. More statistical information together with more simulation studies will contribute to reduce the uncertainty in forecast for heavy oil produced horizontal well projects: The challenge is still ongoing.
Using the Link Between Diagenesis and Fracturing to Accurately Predict, Characterize, and Model Fluid-Flow in Fractured Carbonate Rocks
Authors: Gale J. F. W. , Laubach S. E. , Olson J. , Marrett R.
Published: December 2007

By taking diagenetic processes into account we improved quantitative fracture population description. Using diagenesis information also allows more accurate geomechanical modeling and creation of more realistic fracture patterns for use in fluid-flow simulation. Mechanical rock properties and fracture attributes change with diagenesis and fracture architecture depends on rock properties (particularly subcritical crack index) at the time of fracturing. Preservation of fracture void space depends on cement precipitation synchronous with fracture opening that obeys systematic rules. The greatest effect on large fractures is from later cements, which are typically heterogeneous in distribution.
Feasibility Study of CO2 Injection for Heavy Oil Reservoir After Cyclic Steam Stimulation: Liaohe Oil Field Test
Authors: Luo R. , Cheng L.-S. , Peng J.-C.
Published: December 2007

Because of the favorable properties of CO2 it has been used to enhance the recovery of oil for a long time. But this technology is under slow development in China for lack of rich CO2 resource until some CO2 reservoirs were found in recent years.

Using simulation and reservoir-engineering method, this paper presents the feasibility study of CO2 injection for heavy oil reservoirs following cyclic steam stimulation. Pilot tests were conducted to several wells in Lengjiabao heavy oil reservoirs in Liaohe oilfield, China. Some wells got good effect, while some wells got poor effect. And the results from the simulation and field pilot tests are evaluated economically. Study shows that for common heavy oil reservoir after cyclic steam stimulation, the higher the oil viscosity, the greater the CO2 utilization ratio, and the more feasible CO2 stimulation process; for extra-super heavy oil, 1-3 cycles steam huff-n-puff were performed as necessary, followed by CO2 stimulation process so that good benefit could be gained. These results are of significance for field operation and production of heavy oil.
Field Pilots of an Innovative Real-Time Testing Technique for Separate-Layer Water Distribution
Authors: Wang Zhongguo , Wang Qingfa , He Guixin , Zhang Huishu , Li Ning , Zhang Huixin
Published: December 2007

Based on the traditional water injection technology using off-center choke mandrels for separate layers, an innovated technique for real-time downhole injection-rate adjustment for multiple separate layers was studied, which achieved real-time stepless and continuous adjustment of the desired downhole injection-rates for different separate layers. The technique enhanced the injection-rate adjustment efficiency for a more qualified water flood program and improved the overall production effect in a water-injection field.