bluuebunny/crossref_metadata_2025 huggingface dataset:
Calibrating Permeability Heterogeneity at the Core Scale to Static and Dynamic Data
Authors: Soltani A. , Le Ravalec-Dupin M. , Fourar M.
Published: September 2008

Special core analysis techniques are often based on the assumption of uniform petrophysical properties of core samples. This assumption is obviously erroneous for heterogeneous core samples. This paper presents an integrated approach for characterizing permeability heterogeneity at the core level. The method combines the results of laboratory core flooding with already developed field scale history matching techniques to identify a 3D heterogeneous permeability field at the core scale. We focus on core samples with local heterogeneities. Their 3D porosity maps are preliminary obtained using conventional tomography techniques. Production data are measured when performing a viscous miscible displacement experiment: a high viscosity glycerin displaces a low viscosity brine at a constant flow rate. Concentration maps are collected at successive times during displacement using a medical CT device. A 1D permeability profile can be determined from the variations in the slope of the pressure signal against front location inside core samples. The 3D permeability fields are modelled using a relationship such as log(k(x)) = Aϕ(x) + b(x) where A is a constant and b(x)is a realization of a random function characterized by a mean, a variance and a variogram. We developed an assisted history-matching process, which takes advantage of all the available static and dynamic data to model permeability heterogeneity inside core samples. A first guess is initially generated honoring the measured Δp(t) variations along the flow axis. This first guess is subsequently modified until the mismatch between dynamic data and fluid flow simulated answers is minimized. To do so, we use a gradual deformation based optimization method, which allows us to vary any given distribution from one or a few deformation parameter(s) while preserving the overall spatial variability. The proposed method is fast and non-destructive. The final 3D permeability map honors the measured dynamic data and respects the spatial variability of the collected static data.
The Contradiction in the Lower Tertiary Deepwater GoM
Authors: Wiltgen Nick A.
Published: September 2008

Exploration in the Gulf has progressively moved farther and farther offshore. Initially oil companies concentrated on the shelf and then moved into the deep water and the Miocene trend. The Miocene is a well established trend with a considerable amount of producing acreage. With the acquisition and processing of data farther offshore, attention has switched to a new trend in the Lower Tertiary. The Lower Tertiary sits beneath the Miocene and is older.

The Tertiary time period includes Pliocene, Miocene, Eocene and Paleocene. We tend to lump everything below the Miocene into what we call the Lower Tertiary because our Wilcox sands are Paleocene and Eocene in age. Most of the cumulative GOM production has been Miocene in age.

This is an emerging play in the deepwater Gulf of Mexico, to date there have been 12 announced discoveries out of 19 wells drilled (Figure 1). This trend data is only for Alaminos Canyon, Keathley Canyon and Walker Ridge. There are additional penetrations along trend to the northeast.

There is a contradiction between traditional interpretation and NMR data in the Lower Tertiary. An NMR log (CMR) was run with the aim of identifying the best reservoir intervals of Porosity, Swir, and Permeability. The NMR log has many responses depending on the borehole fluid, free fluid and viscosity.

These results will be discussed.

Oil bearing interval with Swir higher than Sw CMR porosity undercalled in oil-bearing interval Little free fluid in oil-bearing interval Calibration of Klog permeability to core

Traditional logs indicate the presence and quantity of oil, but provide no information on its quality. NMR is sensitive to oil viscosity. NMR can be misleading in the presence of viscous oil as the oil signal can overlie the bound fluid volumes, resulting in the incorrect evaluation of the reservoir in an oil base mud system. The NMR must be used with caution in an oil base mud system (OBM).
Successful Deployment of Innovative Completion Technology Designed for Multi-Stage Fracturing Treatments in Horizontal Producers Achieved Significant Rate Increase in Saudi Arabia
Authors: Solares J. R. , Giraldo C.A. Franco , Al-Marri H. , Al-Hussain H. , Abualhamayel N. , Ramanathan Venkateshwaran , Ishteiwy O. A. , Johnson Bryan
Published: September 2008

One of the key strategies in Saudi Aramco's optimum gas development project includes drilling single and multilateral horizontal wells designed to achieve maximum reservoir contact to maximize productivity. This strategy has proven very successful over the past few years as the majority of horizontal gas producers have yielded excellent results, with open-hole completions in particular. Consequently, most of the planned future wells will be drilled as open-hole horizontal completions.

However, due to the complex nature of the Khuff reservoir some wells have experienced complications during the drilling phase, encountering unexpected reservoir challenges, and hence not meeting production targets. These wells require stimulation to regain their productivity, but the available choices to achieve effective stimulation in horizontal open-hole completions have traditionally been limited at best. Previous stimulation attempts with coiled tubing have yielded modest improvements mainly due to the difficulty in accessing the long, deep, and high pressure/temperature zones requiring treatment. Bullheading treatments at high injection rates have also yielded similar modest well productivity enhancement. Consequently, Saudi Aramco field tested an innovative new completion technology that provided the ability to selectively fracture stimulate multiple zones along the horizontal section, yielding excellent and highly promising results which compared favorably with the performance of non-stimulated offset wells.

It is well known in the industry that fracture stimulating horizontal open-hole completions with conventional methods is a challenging endeavor, and that often-time results are disappointing. The new completion technology overcomes challenges associated with horizontal well fracturing, and provided a tool to achieve effective stimulation. Through this technology multiple mechanical isolation points are created in the wellbore, using specially designed multiple open-hole packers, and then selected zones of varying lengths can be individually treated in accordance with reservoir characteristics and production targets.

This paper details the planning and design processes leading to the implementation of the technology, the experience and lessons learned during deployment of the completion, and the stimulation treatment execution and post-stimulation results. Lessons learned from this successful experience are discussed as a way to enhance the benefits from this promising technology.
Predicting Sorption-Induced Strain and Permeability Increase with Depletion for CBM Reservoirs
Authors: Clarkson C. R. , Pan Z. , Palmer I. , Harpalani S.
Published: September 2008

It is well known that absolute permeability changes occur in coalbed methane (CBM) reservoirs during primary depletion or enhanced recovery/CO2 sequestration operations. Sorption-induced strain in CBM reservoirs, also known as matrix-shrinkage or -swelling, may dominate permeability changes at low pressures, as is the case for CBM wells undergoing primary depletion in the Fruitland Coal fairway of the San Juan Basin.

Several analytical models have been developed to predict changes in coal permeability as a function of stress and sorption. Most models, however, utilize an empirical method for estimating sorption-induced strain. Recently, a theoretical model for sorption-induced strain was developed and applied to single-component adsorption/strain experimental data. The new model was developed from basic thermodynamic principles and is more predictive than the empirically-based approaches. In this paper, the theoretical model is expanded to incorporate multi-component adsorption models that are more rigorous, and sometimes more accurate, than the commonly-applied Extended Langmuir equation. This improves predictions of multi-component gas sorption-induced strain, as demonstrated by comparison to experimental data. The new sorption-induced strain model is then used to calculate the sorption-strain component of the popular Palmer and Mansoori equation, which in turn can be used to model permeability changes during both primary (single or multi-component gas) and enhanced recovery operations. Finally, the coupled sorption-strain/permeability model, incorporated into an analytical simulator, is used to predict and match permeability growth in a producing CBM well in the Fruitland Coal fairway, which has a binary (CH4+CO2) sorbed/produced gas composition.

Matches to field-derived permeability growth using the new model are accurate but non-unique, due to lack of available data, particularly rock mechanical properties. Given the availability of rock mechanics and adsorption isotherm data, the rigorous thermodynamic basis of the new model should allow for more accurate predictions of coalbed permeability changes, but further testing is required.
Characteristic Research of Air Injected Hydrocyclonic Separators
Authors: Jiang Minghu , Zhao Lixin , Sun Fuqing , Tan Rong , Song Hua
Published: September 2008

An air-injected de-oil hydrocyclone was developed, which has a dual function of hydrocyclonic separation and floatation separation so as to have better separation efficiency by overcoming the disadvantages of normal used hydrocyclone and floatation facility to a great extent. It has a similar structure with normal hydrocyclones, but an outer shell was added on vortex cavity, large cone section, or fine cone section, which was made by a kind of micro-pore material. Basic separation principle, prototype structure, experimental process and facilities are introduced. The effect of geometric parameters, including vortex finder diameter and length, micro-pore diameter, and different operating conditions, such as flowrate, split ratio, gas-liquid ratio, and air-injecting position, were studied. Laboratory experiments were carried out first to provide basis for field tests. The field research indicates that, for around 1000 mg/l polymer-flooding oily-water, the optimum flowrate is 4.20 m3/h for the testing prototype, the split ratio should be 30%; gas-liquid ratio 0.45. It also shows that 20-40 μm micro-pore materials are optimum diameter for hydrocyclonic separation enhancement. Research indicates that it has satisfied separation effect, which is feasible for emulsified oil treatment. This kind of hydrocyclone will have better application prospect in petrochemical, environmental field, especially for offshore application.
Fluid Characterization for Miscible Floods
Authors: Yuan Hua , Chopra Anil , Marwah Vineet , Stalkup Fred
Published: September 2008

The compositional simulation of a miscible gas injection process depends on an equation of state (EOS) model. An EOS model should not only predict traditional black oil PVT experiments for reservoir fluids but also experiments that give gas-oil compositional information, such as swelling tests, multi-contact tests, and slim-tube MMP. The two most common methods used to estimate MMP with an EOS model are traditional slim-tube simulation and, more recently, the analytical tie-line method. In most cases, the MMP computed from a slim tube simulation agrees well with the analytical tie-line method, but on some occasions, the MMP computed from the analytical method differs significantly from the value derived from slim-tube simulation. Additionally, for some gas floods, slim-tube simulation seems to identify an apparent MMP, but the analytical tieline method fails to give a solution. In this paper, we identify the reason behind these apparent discrepancies: physical dispersion and phase behavior. Thereafter, we propose a reservoir fluid characterization procedure for miscible gas floods that more accurately represents the interaction of flow and phase behavior. We demonstrate this approach for two different gas floods.
Rapid Country Entry Risk Screening Using Objective Relevance-Weighted Model for Transnational Petroleum Initiatives
Authors: Rajan Surya
Published: September 2008

In OECD Europe, oil consumption increased from 13.7 MMbbl/d in 1990 to 15.5 MMbbl/d in 2005, net increase 1.8 MMbbl/d. Oil consumption is expected to rise only 0.1 MMbbl/d in OECD Europe over the next 15 years. In Russia and FSU countries, though, oil consumption is expected to dramatically increase in next 15 years after years of low consumption levels. Moreover, developing Asia and Middle East is expected to reshape future oil markets. As Rate of Reserve Replacement continues to be challenged, International Oil Companies (IOCs) face competition from other IOCs as well as from entrepreneurial national oil companies (NOCs) aggressively looking to develop assets domestically and overseas. A disproportionately large fraction of reserves are controlled by a few NOCs. Downstream resources are similarly pursued by NOCs and IOCs alike.

Rapid, objective risk assessment of potential countries or regions targeted for petroleum investments has become an increasingly essential part of business development in an equally dynamic global market. Though a critical decision point for transnational ventures, Country Entry Risk Screening remains time consuming, complex, often subjective, and generally provides no basis for objective comparison between candidate locations.

Application of the Rajan-Vikas model1 enables apples-to-apples comparison between shortlisted countries or regions. Applicable to IOCs, NOCs, or Service Companies (SCs) alike, the model uses scores on a consistent relevance-weighted risk factors matrix to perform simplified objective assessment of a potential country or region under consideration. Screening of candidate locations prior to actual project due diligence is greatly expedited. Model application produces reusable artifacts for quick future reference or input for later detailed project risk management.
Drillstem Testing For High Pressure Deepwater Wells: A Noncemented Floating Tieback Liner Technique
Authors: Hussein Sameh , Scoular Tom , Luo Yuejin
Published: September 2008

Current and future offshore exploration activity is penetrating to deeper reservoirs, driving the need for increased drillstem testing (DST) for high pressure and high temperature wells. Typically, liners are tied back to the surface to achieve reliable wellbore integrity and flow. In the past, these tiebacks require expensive cementing operations which also limit future wellbore re-entry options.

An innovative non-cemented floating liner tieback with reliable floating seals can improve the entire DST process by eliminating the cost and risk of cementing operations. In addition, the operator is able to retrieve the casing tieback and have the option to use the same well for appraisal or development phases.

The paper discusses the floating tieback system and details a case history on a high pressure well in which the operator completed the DST operation safely and met all well objectives. Discussion of system reliability includes casing design and modeling by both operator and suppliers, plan changes based upon pressure data obtained during the drilling phase, detailed operational procedure in a deepwater environment, successful tieback retrieval and future operations.
Field Applications of Capacitance-Resistive Models in Waterfloods
Authors: Sayarpour M. , Kabir C. S. , Lake L. W.
Published: September 2008

Application of fast, simple and yet powerful analytic tools, capacitance-resistive models (CRMs), are demonstrated with four field examples. Most waterfloods lend themselves to this treatment. This spreadsheet-based tool is ideally suited for engineers who manage daily flood performance. We envision CRM's application to precede any detailed full-field numerical modeling.

We have selected field case studies in a way to demonstrate CRMs capabilities in different settings: a tank representation of a field, its ability to determine connectivity between the producers and injectors, and understanding flood efficiencies for the entire or a portion of a field.

Significant insights about the flood performance over a short period can be gained by estimating fractions of injected fluid being directed from an injector to various producers and the time taken for an injection signal to reach a producer. Injector-to-producer connectivity may be inferred directly during the course of error minimization. Because the method circumvents geologic modeling and saturation matching, it lends itself to frequent usage without intervention of expert modelers.
Utilizing 4D Microgravity To Monitor Water Encroachment
Authors: Alshakhs Mohammed J. , Riis Erling , Westerman Robin , Lyngra Stig , Al-Otaibi Uthman F.
Published: September 2008

The common wisdom is that gravity methods have limited application in the oil industry although they have long been available. The main use of gravity has been for exploration purposes. 4D microgravity monitoring is another new promising gravity application to monitor changes of fluid contacts. Some successful 4D monitoring surveys have been conducted in the industry revealing that this technique is a proven technology in monitoring of gas-water contacts.

This paper studies the ability of microgravity to capture movement of the injected water in a giant carbonate field. The oil-water case is more difficult due to the significantly lower density contrast as compared to the gas-water case. Monitoring water floodfront in the field is a key factor in applying successful reservoir management practices to maximize recovery and prolong the field life. The monitoring of inter-well fluids would characterize any pre-mature water breakthrough to allow planning and design of appropriate remedial well interventions. The current applied monitoring tools such as carbon-oxygen and resistivity logs can only detect fluids near to the wellbore due to their shallow radius of investigation. For the study field, 4D seismic cannot be used for fluid movement detection due to issues related to formation acoustics impedance and data quality.

The study has shown that surface microgravity monitoring could successfully detect the inter-well fluid changes due to water injection with a high precision tool (0.01 microgal). It also shows that microgravity monitoring can capture water bodies located hundreds of meters away from the location of the 4D measurement.
Interaction Between Intelligent Well Applications and Reservoir Management—A Comprehensive Thermal Modeling Technology for IWS Well
Authors: Sun Kai , Constantine Jessse , Coull Craig
Published: September 2008

Can we predict how Intelligent Well Systems (IWS) and equipment operate in various wellbore conditions to meet production enhancement targets? This paper presents a developed modeling technique and demonstrates how this technology can guide IWS equipment operations/design to meet production enhancement targets for a deepwater multiple-zone IWS water injection well.

Since IWS solutions typically address multi-zone (commingled) production or injection wells, it is important to develop a well deliverability model. Within this model, several key features include; a.) Multi-zone inflow/delivery including the unique zonal reservoir and fluid properties, b.) Multiple production/injection flowpaths to accommodate tubing flow for one zone and annulus/tubing flow for other zones, c.) Simulation of the effect upon wellbore pressure and flow distribution due to geometry changes within a completion string (i.e., gravel pack system, flow control equipment, etc), d.) Simulation of the fluid temperature profile and the effect on pressure and flow profile. Industry-available nodal analysis products have historically shown limitations in these types of applications. To fill this purpose, a comprehensive thermal model and an integrated analysis tool have been developed.

The modeling results provide an insight into how choking of downhole valves and tubing wellhead pressure impacts the injection fluid flow distribution. For any IWS operation scenario, the flow distributions, wellbore pressure profile, fluid temperature profile, and the fluid velocity profile can be predicted. This assists in determining any erosion concerns on equipment, flowing differential pressures through the valves and expected loads from temperature changes. This flexibility is the added value, where operators can choose the operational configuration to achieve their production objectives. The model results have been compared with several third party softwares and real case production data. Analysis and comments of the comparison are provided.
The Importance of Deposition Measurements in the Simulation and Design of Subsea Pipelines
Authors: Akbarzadeh Kamran , Ratulowski John , Davies Tara
Published: September 2008

Conventional practices for estimating the amount of deposited organic solids in pipelines are usually based on either the assumption of total deposit equal to total precipitate or the predictions with simulation packages using limited lab-scale deposition data with stock tank oil under laminar flow in small flow loops. Such practices, however, often lead to either overdesign or underdesign of pipelines and surface facilities. For optimized designs, more representative lab-scale deposition measurements which lead to more representative simulations are therefore required. In this work, a high pressure deposition cell which operates based on the Taylor-Couette (TC) flow principals and can mimick pipeline operating conditions is used to generate more representative deposition data with live reservoir fluids under turbulent flow conditions. The analogy between TC flow and pipe flow is explained and a scalability flow chart for linking the lab scale deposition data from TC configuration to pipe configuration is presented. Through a case study, the scaled deposition data is then used to tune a wax deposition model in the OLGA®5 simulation package. Next, the tuned model is applied to predict wax deposition under actual production and transportation conditions. The importance of tuning the deposition models with live fluid data under turbulent flow conditions is also shown by comparing to results obtained from conventional dead oil low shear data.
A Practice of Applying Downhole Real Time Gauge Data and Control-Valve Settings to Estimate Split Flow Rate for an Intelligent Injection Well System
Authors: Sun Kai , Coull Craig , Constantine Jesse
Published: September 2008

Because an Intelligent Well System (IWS) normally addresses multiple zones of production/injection, knowing the exact flow allocation for each controlled zone is important for well optimization and management. In an IWS well, downhole gauges are usually installed at the upstream and downstream sides of a downhole control valve to monitor pressure and temperature. This type of gauge installation configuration makes it possible to estimate the flow allocations through the downhole valve. Many discussions and practices have applied this method, but seldom have successful application cases been published until now.

This paper will discuss a recent application of this method to estimate the flow rate for a dump-flooding intelligent injection well system. In this case, the downhole control valve was kept 100% open, a condition which has been well-recognized for its difficulty in flow rate estimation.

Verification was completed by comparing the different time series predicted results with the flow rate logging data. The comparison showed differences within ±10% range when the injection flow through the choke reached steady state flow conditions.

A discussion of three key factors addresses the accuracy of the method: The compensated differential pressures though the valve.Reliable flow characterization modelsFluid p-v-T behavior impact.

Flow tests provide reliable information to characterize flow through the control valves. A comprehensive hydraulics model addresses the hydrostatic and frictional pressure drop, analyzes fluid p-v-T behavior, and solves the flow rate/pressure profile numerically.
Injectivity Characteristics of EOR Polymers
Authors: Seright R. S. , Seheult Mac , Talashek Todd
Published: September 2008

This paper estimates injectivity losses associated with injection of EOR polymer solutions if fractures are not open and considers the degree of fracture extension if fractures are open. Three principal EOR polymer properties are examined that affect injectivity: (1) debris in the polymer, (2) polymer rheology in porous media, and (3) polymer mechanical degradation. Using Berea sandstone cores (100-600 md) and various filters and filter combinations, an improved test was developed of the tendency for EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers.

Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft.

For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea.

Considering the polymer solutions investigated, satisfactory injection of more than 0.1 PV in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects where polymer solutions are injected.
An Integrated Theoretical and Experimental Study on the Effects of Multiscale Heterogeneities in Matrix Acidizing of Carbonates
Authors: Izgec O. , Keys R. , Zhu D. , Hill A. D.
Published: September 2008

Carbonates often have small (micron) to large (centimeter) scale heterogeneities in flow properties that may cause the effects of injected acids to differ greatly from what is predicted by a model based on a homogenous formation. To the best of our knowledge, there are neither theoretical nor experimental studies on the effect of large scale heterogeneities (vugs) on matrix acidizing. The abundance of carbonate reservoirs (60% of the world's oil reserves) and the lack of a detailed study on the effect of multi-scale heterogeneities in carbonate acidizing are the main motivations behind this study.

In this work, we first present a methodology to characterize the carbonate cores prior to the core-flood acidizing experiments. Our approach consists of characterization of the fine-scale (millimeter) heterogeneities using computerized tomography (CT) and geostatistics, and the larger-scale (millimeter to centimeter) heterogeneities using a connected component labeling algorithm. In order to understand the connectivity of vugs and thus their contribution to flow, a 2D visualization algorithm, connected component labeling (CCL), was implemented in a 3-dimension system.

After multi-scale characterization of the cores, acid core-flood experiments were conducted. 4-inch diameters by 20-inch long cores were used to decrease the geometric effects on the wormhole path. The post acid injection porosity distribution and wormhole paths were visualized after the experiments.

The results demonstrate that acid follows not only the high permeability paths but also the spatially correlated ones. While the connectivity between the vugs and size of the core is the predominant factor, spatial correlation of the petro-physical properties has less pronounced effect on wormhole propagation in acidization of carbonates.
Irreducible Water Saturation Has Been Determined As the Key Factor Governing Hydrocarbon Production from Low Permeability Carbonate at the Wattenberg Field in the Denver Julesburg Basin
Authors: Yang Yuanhai , Birmingham Thomas
Published: September 2008

It is commonly known that geological structure and its resultant natural fractures are the predominant factors governing hydrocarbon production from carbonate reservoirs. Through a detailed petrophysical study on a low permeability carbonate play, the authors have obtained new understandings toward the reservoir properties of low permeability carbonate. First, in absent of major geological structures, reduced relative permeability to hydrocarbon is the primary trapping mechanism. Second, the irreducible water saturation range for low permeability carbonate increases significantly. Third, the enlarged irreducible water saturation range makes the curve of relative permeability to hydrocarbon much steep. Therefore, the relative permeability to hydrocarbon is very sensitive to water saturation, and formation water saturation becomes a critical factor affecting hydrocarbon production. The results of this petrophysical study have been successfully applied to identity the "fairways" among a huge low permeability carbonate deposition.
Experimental Study on Downhole Gas-Liquid Separation and Produced Water Reinjection
Authors: Wang Zunce , Wang Xiaoping , Li Sen , Xu Yan , Zhang Jinglong , Lv Fengxia
Published: September 2008

Gas well fluid accumulation caused by floodout is an important problem to restrict natural gas exploitation. To solve the problem by using dewatering gas production is an effective method. For convention gas well production with water withdrawal technics, accumulated water is lifted to ground, gas-liquid mixture is treated on the surface, and separated water is reinjected back into the formation, which resultes in many problems, such as more equipment and investment needed, and other environmental pollution issues. For the purpose of clean, low input and high output, a cost-effective and simple downhole gas-liquid separation and water injection system is developed.

A downhole gas-liquid separation and water reinjection process is proposed in this paper. The core components of the system are the improving hollow rotor screw pump and downhole gas-liquid separator. The gas-liquid recovery and impetus providing for the separation and reinjection water pressure are achieved through a hollow screw pump rotor. The separated gas is produced through casing, and isolated from the underground water through hollow screw pump rotor to provide access for reinjection. The system experiments carried out at Shen 14-6 gas well in Shenyang Oil Production Plant, Liaohe Oilfield, China get a satisfactory result.
Chemical Intervention Technology For Low-Risk Annular Isolation In Existing Gravel Packed Wells And Uncemented Annuli
Authors: Cole-Hamilton Jim , Curtis James
Published: September 2008

It is often desirable to be able to intervene to isolate specific areas within a wellbore. Throughout the life of a well, undesirable changes to production such as increased water may occur that cannot be easily dealt with using mechanical means, unless the completion has been designed with this in mind. Examples include flow through uncemented annuli, or from part of a gravel packed completion. In such cases, a possible solution may be to pump a treating fluid with properties that will provide the isolation required. Several different systems are available such as crosslinked polymer fluids, portland cement, or other hard setting materials.

This paper reviews the properties of one such product, a magnesia cement system, evolved from chemistry that had previously been employed in other applications. The new technology uses fine-grained materials that can be squeezed though small restrictions such as narrow annuli, slots or perforations, or through well screens and into the gravel pack beyond, where later they will set hard and provide selective isolation of the treated section to prevent the flow of unwanted fluids. As with the original chemistry, the new system is composed of acid soluble components, allowing the solid set material to be removed in the future should it be required.

This paper will identify the requirements associated with selecting hard setting materials use in for zonal isolation. It will discuss the development of this squeezable magnesia cement system, showing how it meets these requirements. The results of extensive laboratory evaluations will be reviewed and recent case histories will be discussed.

This technology is expected to find wide application in many existing gravel-packed and un-cemented wells worldwide, when low risk long-term zonal isolation becomes required.
Enabling Efficient Permanent Production Monitoring of Advanced Well Completions in Saudi Arabia Using Fiber Optic Distributed Temperature Sensing
Authors: Hembling Drew , Berberian Garabed , Carter Neale , Naldrett Garth
Published: September 2008

Although the recent focus in the industry on maximum reservoir contact (MRC) and Advanced well completions has provided significant improvements in reservoir depletion it has caused some data gathering disruptions for companies operating these wells. In particular, the options to perform well logging are much reduced, and the costs of performing a production log are extremely high. This is related to both the costs of the more advanced horizontal well logging tools and the more expensive logging methods, such as coiled tubing and tracker systems, used for the conveyance of these tools into the wellbore.

In an effort to acquire high quality downhole data in a timely manner in MRC wells, Saudi Aramco set about investigating the alternatives to traditional production logging methods. A technology gaining greater industry acceptance in recent years is permanently installed Distributed Temperature Sensing (DTS) and this became the focus of investigation. The limitations of conventional DTS technology was, however, soon realized; In particular the limited temperature resolution offered was not sufficient for evaluating high angle maximum reservoir contact intelligent wells. At the time of investigation a new generation of DTS technology became commercially available, providing a 10-fold improvement in measurement resolution. This allowed Saudi Aramco to proceed with field trials of the technology.

This paper will present the requirements for advanced DTS technology to provide quality data sets for use in rate and density modeling in highly deviated MRC wells.

In addition, the installation of the downhole hardware in an advanced well completion and the data from the field trials will be presented.
The Displacement of Oil by Polymer Slugs Considering Adsorption Effects
Authors: Ribeiro P. M. , Pires A. P.
Published: September 2008

Oil displacement by injection of chemical solutions is a widespread Enhanced Oil Recovery method. Analytical models for one-dimensional displacement of oil by water with chemical components have been developed since the 1960´s. This problem involves complex physical-chemical processes of interphase mass transfer, phase transitions and transport properties changes. The continuous injection of this kind of fluid would be very expensive, so, the injection of chemical slugs is an attractive alternative to improve the recovery of mature oil fields. The continuous injection of chemical solutions is a Riemann problem, easily solved by the introduction of a self-similar variable. Nevertheless, the slug injection is not self-similar, and the problem becomes much more complex from the mathematical point of view. This paper presents the analytical solution of chemical slug injection in an oil reservoir. A flow potential associated with the conservation of the aqueous phase is introduced as a new independent variable instead of time. This change of variables allows the system splitting into one equation (lifting equation) and a thermodynamic system (auxiliary system). The number of auxiliary equations is less than the number of equations in the compositional model by one. In this paper different adsorption isotherms were analyzed. The transport equation solution, or lifting problem solution involves interaction between waves of different families and allows the design of slug sizes in order to obtain the maximum efficiency of this process. Another important application of these solutions is the prediction of chemical flooding regardless of the transport properties (relative permeabilities and viscosities). If the mobility ratio is close to one, this model may be applied in the development of streamlines simulators.
Wax Deposition in Pipelines: Flow-Loop Experiments and Investigations on a Novel Approach
Authors: Benallal Amine , Maurel Philippe , Agassant Jean François , Darbouret Myriam , Avril Guillaume , Peuriere Eric
Published: September 2008

Models used to predict wax deposits in oil production pipeline are based on thermodynamic properties coupled with several Fick's diffusion mechanisms. These models generally need fitting parameters to match computational results to experimental data, and moreover they do not explain all aspects of this phenomenon. One of these aspects is the "sticking" of the deposit to the wall. In this study, it is demonstrated that the deposit could result from flow patterns caused by rheological factors. Indeed, thermodynamic properties create the onset of wax crystals, and diffusion mechanisms result in the displacement and accumulation of wax in a particular region. This results in rheological changes that modify the flow pattern and create an unyielded region near the wall, namely a wax deposit. To highlight this process, experimental tests of wax deposition were performed on the Lyre loop at IFP-Lyon in Solaize, France. This loop is 140 meter long with a 2 inches internal diameter and is fully temperature-controlled. A wax deposition section consisting of a 7 meter sub-cooled section is integrated in this loop. A one-meter spool piece can be retrieved to observe and sample the wax deposit. Temperature, pressure drops and flow rate were monitored. The wax deposit was observed after 4h, 24h and 72h and was sampled for rheological measurements. The experimental results are presented in this paper. In addition, to analyse this experimental data, a numerical model based on the previously described physical aspects is implemented, and the results show good agreement with experimental data.
Prediction of Proppant Transport from Rheological Data
Authors: Harris Phillip C. , Walters Harold G. , Bryant Jason
Published: September 2008

Fracturing gels are formulated and viscosity parameters are measured to predict whether and help ensure that a fracturing treatment will be successful. Steady shear viscosity cannot measure the elastic component of viscoelastic fluids. Dynamic oscillatory shear can provide measurements of elastic properties, but such measurements are made in the absence of any particles. A third technique, a slurry viscometer (SV), can incorporate particles and measure proppant transport characteristics of the fluid. This paper compares all three measurement techniques for verification of transport prediction.

Steady shear viscosities of gelled fracturing fluids were measured using couette viscometers. Viscoelastic characteristics of the same fluids were measured with a dynamic oscillatory viscometer to determine G’ and G" moduli and crossover frequency. Proppant particles were added to these same fluids and properties measured with the SV to determine elastic transport and viscous transport times.

Comparison of the three data sets shows that the elastic modulus, G’, and crossover frequency have a high correlation with elastic transport times measured with the SV. Steady shear viscosities above 10 s-1 do not directly correlate with transport times.

Dynamic oscillatory measurements have been thought for years to predict particle transport phenomena, but any correlations that were generated could be incomplete because particles are excluded from the measurements. The SV does include particles in the fracturing gel, and can be used to verify trends of proppant transport indicated by G’ and the crossover frequency.
The Effect of Elasticity on Displacement Efficiency in the Lab and Results of High Concentration Polymer Flooding in the Field
Authors: Jiang Haifeng , Wu Wenxiang , Wang Demin , Zeng Yeming , Zhao Shiguang , Nie Jun
Published: September 2008

The elasticity of polymer solution is usually disregarded in the studies of polymer flooding. The common viewpoint is that the displacement efficiency is determined by the ratio of the pressure gradient and interfacial tension in the system. But new studies show, when the pressure gradient and interfacial tension are constant, that visco-elastic polymer flooding can achieve higher displacement efficiency (De).

In this paper, based on theoretical analysis and through large amounts of core tests on homogeneous water-wet and slightly oil-wet artificial cores, the influence of visco-elasticity of polymer solutions with different concentrations on De were studied at different capillary numbers (determined by the ratio of pressure gradient to interfacial tension). The results show that when the capillary numbers are the same, the higher the flooding fluid's elasticity, the higher the De and the lower the residual oil saturation in both oil-wet and water-wet cores. In the range of these tests, the effect of elasticity on De is about the same as that of ultra-low interfacial tension chemical flooding. It can also been seen that residual oil starts to mobilize at a lower capillary number with higher elasticity driving fluids.

In addition, flooding experiments in the lab on heterogeneous cores by high concentration polymer fluid show that the higher the concentration and viscosity of the driving fluid, the higher the De. High concentration polymer flooding was tested in 3 fields and show that the additional recovery is nearly 2 times that of conventional polymer flooding, obtaining an incremental recovery of more than 20%OOIP.

This conclusion is useful in further understanding the mechanism of polymer flooding, and it can provide further basis for choosing chemicals and determining chemical flooding designs in the field.
Model Building with Difficult Faults
Authors: Hoffman K. S. , Neave J. W. , Nilsen E. H.
Published: September 2008

Many of the commonly used fault modeling techniques can adequately handle simple structures – even when those structures contain large numbers of faults. It is not the sheer number of faults that is often the stumbling block, but rather the complexity of the fault/fault relationships. Common configurations such as a Y intersection formed by a synthetic/antithetic fault pair can be difficult to model due to the limitations of the framework-building technique. Often the truly difficult situations, such as listric faults, low angle faults, or crossing conjugate faults, are not even attempted – which means that the resulting reservoir models do not correctly represent the subsurface.

Our technique for building a fault framework provides a comprehensive solution for modeling any type of fault shape or fault intersection. Listric faults and Y-intersections, for example, must be treated as special cases with pillar-based methods, and a nested-Y structure is nearly impossible to model with this technique. Low angle faults and low angle intersections also pose problems for pillar-based methods; the low angle intersection can distort the shape of one or both faults. Crossing conjugate faults can create half-Y faults, which neither the pillar method nor the binary tree method can model.

The concept of compound relationships used in our approach, where faults are divided into sections based on their relationships with all faults which touch or cross it, allows independent manipulation of each small section of a fault. In this way, even the complex truncations of crossing conjugate faults are easily handled. The solid models and reservoir grids that are created based on these frameworks incorporate all of the complexity of the interpretation. These models provide a better basis for reservoir management decisions and can be shared by all of the disciplines within an asset team.

The advances in fault modeling shown here provide a comprehensive solution to handle all type of faults and fault intersections without any of the compromises previously necessary. The flexibility of the technique reduces cycle time for building the framework and allows for more in-depth investigation of reservoir properties.
3D RSS for 24" Section Sets Inclination Record on the Grane Field by Introduction of an Integrated Drilling and Surveying Bottomhole Assembly
Authors: Saeverhagen Erland , Erichsen Cato , Nesheim Anders , Waldron Glen
Published: September 2008

To maintain production and reservoir pressure on the Grane field, production, gas and water injection wells today are placed in the outer reaches of the reservoir. Due to the shallow reservoir depth, immediate and high deviation is required in the 24" section, to enable sufficient lateral displacement. Due to short intermediate slot distance, it is also imperative to obtain precise directional measurements to control anti-collision.

The 24" build up section was planned with a continuous DLS of 2.8°/30m starting approx. 150m below seabed, where the well still was vertical, through soft and unconsolidated sand and shale formations, until reaching the required sail angle at 80° inclination, followed by an 860m tangent section to section TD.

Past experience from the Grane field, have shown problems in achieving the required build rate using a conventional PDM-mud motor with high offset tilt angle. Wireline gyro also was the standard solution to obtain directional control in the tight "kick off " area just below the platform, which was very time consuming with survey sensors placed far behind the bit.

The new BHA was designed to achieve all directional objectives, consisting of a 24" 3D RSS system and a combination of Gyro MWD and Magnetic MWD tools integrated in the BHA, thus removing the need for PDM motor and wireline Gyro surveys.

This paper will describe the technology used and the achievements from well 25/11 G-31, where the planned well path was drilled according to plan.