bluuebunny/crossref_metadata_2025 huggingface dataset:
The Application of a New and Unique Relative Permeability Modifier in Selectively Reducing Water Production
Authors: Nelson Scott G. , Kalfayan Leonard J. , Rittenberry William M.
Published: December 2007

The need to reduce water production through the use of low-risk chemical treatments is becoming an everyday reality in the oil and gas industry today. Rising exploration and development costs, along with ever-increasing water management costs, require that cost-effective methods of reducing unwanted water production be developed and implemented. To address this issue, a new relative permeability modifier system has been developed. The RPM is uniquely formulated to effectively treat sandstone or carbonate formation matrices. The relative permeability modifier selectively reduces the permeability to water, without detrimentally affecting oil or gas permeability.

This new water management treatment approach provides simplicity in job application, is viable over a wide range of reservoir types, lithologies, and permeabilities, and can be employed in a broad range of job types, including matrix injection and hydraulic fracturing treatments. This paper summarizes a successful fracturing treatment application employing the new relative permeability modifier.
Mixed-Wet Drainage and Imbibition Relative Permeabilities From the Diffuse Interface Theory
Authors: Papatzacos Paul , Skjæveland Svein M.
Published: December 2007

The Diffuse-Interface model for two-phase flow in porous media is applied to the invesigation of relative permeabilities in unsteady-state flows. It is shown that relative permeabilities have a transient regime where they can be significantly larger than 1. It is also shown that, when normalized by their endpoint values, relative permeabilities can be calculated from formulas involving thermodynamical and capillary pressure functions. The end-point relative permeabilities are linearly related to the fluid velocity, but the coefficients seem to be flow dependent.
Estimating Fracture Gradient in Gulf of Mexico Deepwater, Shallow, Massive Salt Sections
Authors: Barker J. W. , Meeks W. R.
Published: December 2007

Drilling massive salt sections in the deepwater Gulf of Mexico is becoming a frequent occurrence. The abundance of salt and the ability of seismic to image under salt have made drilling massive salt sections common place. It is estimated that over a hundred wells in the deepwater Gulf of Mexico have penetrated salt at both shallow and deeper well depths. As the industry gains experience drilling deepwater, shallow allochthonous salt bodies, several advantages of drilling through, rather than around, salt have emerged. Fracture gradients in shallow salt intervals have proven to be much higher than in non-salt sediments at a comparable depth. As a result of the increased fracture pressure, massive salt sections have been used to extend casing points and eliminate casing strings, resulting in greatly reduced well costs through reduced rig time, well tangibles, underreaming, cement volumes, and mud volumes. Many operators are now choosing to drill massive, shallow salt sections to take advantage of these benefits. In some cases these cost savings have the potential of making marginal deepwater reserves economically feasible to develop and produce. A reliable estimate of the fracture gradient in shallow, massive salt sections is needed to design casing strings and plan mud weights for safe and cost effective wells.

Upon exiting a shallow salt zone, often the formation pore pressure and fracture pressure are very close. Typically this condition results in drilling problems including lost returns, well control events, etc. The proper choice of a mud weight to exit a shallow, massive salt section can be a critical factor for both well integrity and cost.

This paper describes a method to estimate the fracture gradient for a salt formation below a casing shoe. The method is based on experience gained while drilling wells which penetrated substantial salt sections. Also presented are guidelines that can help in selecting a mud weight when exiting the bottom of a massive shallow salt section.
Stress Perturbations Adjacent to Salt Bodies in the Deepwater Gulf of Mexico
Authors: Fredrich J. T. , Coblentz D. , Fossum A. F. , Thorne B. J.
Published: December 2007

Lack of consideration of the geomechanical interaction between salt bodies and surrounding formations has led to documented drilling failures adjacent to salt diapirs1–3, in some cases resulting in individual well abandonment costs of tens of millions of dollars. To address this issue, a three-dimensional non-linear finite element geomechanical simulation effort was initiated to analyze the in situ stress state existing in and adjacent to salt bodies before drilling as well as under producing conditions. This work leverages unique expertise in salt mechanics and computational geomechanical modeling. Non-linear finite element geomechanical models were developed for four idealized deepwater Gulf of Mexico geometries including a spherical salt body, a horizontal salt sheet, a columnar salt diapir, and a columnar salt diapir with an overlying tongue. The analyses reveal that at certain locations for specific geometries: shear stresses may be highly amplified; horizontal and vertical stresses may be significantly perturbed from their far-field values; principal stresses may not be vertical and horizontal (i.e., the vertical stress may not be the maximum stress); and anisotropy in the horizontal stresses may be induced. For some geometries, the vertical stress within and adjacent to the salt is not equal to the gravitational load; i.e., a stress-arching effect occurs. Analogously, the assumption that the horizontal stress within a salt body is equal to the lithostatic stress is shown to be incorrect sometimes. The modeling also suggests an alternative explanation for the so-called rubble zones thought to occur beneath and/or adjacent to salt diapirs, in that they may be an intrinsic consequence of the equilibrium stress field needed to satisfy the different stress states that exist within the salt body and in the non-salt surrounding formations. We demonstrate with an example how this work can enable more rigorous planning of well locations and trajectories by providing more accurate estimates of the vertical and horizontal stresses around and within salt bodies for wellbore stability analyses so as to avoid areas of potential geomechanical instability, and to enable accurate fracture gradient prediction while entering, drilling through, and exiting salt bodies.
Hole Cleaning and Cement Design for Specific Formation Types
Authors: Rueda Francisco , Heathman James , Serrano Mario
Published: December 2007

This paper describes a new design procedure developed to help effectively remove drilling fluid components, particularly thick layers of partially dehydrated filter cake, from the casing/wellbore annulus after the fluid has been exposed to downhole conditions, including, temperature, pressure, fluid loss, and static time. This new methodology can be conducted in any properly equipped cementing and drilling fluids laboratory.

To isolate the zones of a well and allow a reservoir to be produced safely and economically, drilling fluid and drill cuttings should be removed from the annulus and replaced by a competent cement sheath that bonds and seals the casing to the wellbore. Simple laboratory tests performed with commercially available testing devices help the designer evaluate the cleaning efficiency of flushes, spacers, and surfactants under simulated downhole conditions. These tests can determine the following parameters:

Force required to mobilize the drilling fluid Chemical effects of preflushes and/or spacers used for mud removal and filter-cake removal and their effect on filter-cake permeability

These parameters, combined with a mathematical model that helps determine the fluid properties and annular velocities required to effectively remove drilling fluid, provide a realistic simulation of the displacement process.

Case histories and well logs illustrate how the displacement process can be significantly improved when designers use a procedure that includes the following steps:

Conduct laboratory tests. Run a mathematical simulation model. Design fluids to address issues such as cementing across unconsolidated and/or high-permeability formations.
The Use of Lightweight Cement Slurries and Downhole Chokes Improves the Success of Primary Cementing on Air-Drilled Wells
Authors: Brown Devin , Ferg Thomas
Published: December 2007

The success of a primary cement job is often measured according to effective zonal isolation, achieving the designed top of cement and avoidance of remedial cementing. In the San Juan and Rio Arriba Counties of New Mexico, many Mesa Verde and Dakota wells are air-drilled because the Mesa Verde formation is sub-normally pressured and is naturally fractured. This combination makes the Mesa Verde easy to hydraulically fracture during normal drilling and cementing operations. Therefore, meeting the primary cement job success criterion is particularly challenging.

Cementing of casing within an air-drilled wellbore allows the slurry to free fall. Cement-free fall can cause severe surge pressures at the bottom of the hole, leading to hydraulic fracture initiation and loss of lift. The use of a downhole choke can be employed to prevent these processes from occurring.

Because mud filter cake does not exist in an air-drilled hole, the lead water spacer and cement must wet the casing and wellbore rock surfaces. Loss of the lead water spacer in conjunction with cement water loss can produce dehydration of the cement column, leading to an increase in cement viscosity and equivalent circulating density. Careful control of cement-free water and fluid loss are required to prevent this from occurring. Furthermore, placing cement across targeted completion intervals which have low fracture gradients requires the use of a high-compressive strength, low-density cement which is competent and capable of maintaining zonal isolation during the completion and production phases of well construction.

This paper will outline the evolution of the cementing practices used for the Mesa Verde and Dakota wells drilled in the 29-6 Unit (T29N – R6W, New Mexico) from 1998 to 2002. It will illustrate how cementing changes enabled the primary cementing to be successfully completed in a single stage instead of two, which has translated into cost savings for both the drilling and completion phases of a well. The impact of using a downhole choke for the pumping and placement of these primary cement jobs will be illustrated and discussed. The function of the cement additives on slurry properties will also be discussed as they pertain to these cement jobs.
Using Multicomponent Seismic Data to Better Understand Reservoir Characteristics
Authors: Waggoner John , Kristiansen Pål
Published: December 2007

Multicomponent (3C on land/4C on seabed) seismic data has unique information content that has proven to be useful in structural interpretation. As such, development of 3C/4C seismic acquisition, processing, and interpretation systems has increased over the past few years within the geophysical community. These improvements have shown that 3C/4C seismic information has application beyond structural interpretation, and can reveal internal reservoir characteristics that are directly useful in understanding and managing the reservoir.

After reviewing the principles, applications, benefits, and recent advances in 3C/4C seismic technology, all from an engineering perspective, this paper concludes that 3C/4C seismic has utility beyond the known niche applications, such as gas cloud imaging, to applications with broader benefit, such as fracture characterization and drilling hazard identification, as well as better reservoir property prediction and the ability to discriminate lithology (sand/shale) and fluid (water, gas, fizzy water). These conclusions are illustrated with recent case studies.
Design and Construction of Pilot Wetlands for Produced-Water Treatment
Authors: Jackson L. M. , Myers J. E.
Published: December 2007

Wetlands are not well understood by the oil industry, environmental contractors and regulatory agencies. The pilot and full-scale treatment performance data sets to properly design wetlands do not exist in public domain literature. Wetland design equations based on the average of the bad and good data sets create wetlands that are almost never sized properly. Engineers trained to work with "black box" treatment technologies tend to shy away from the "green box" treatment technologies. The treatment performance of pilot wetlands ranges from poor to excellent, in part, due to a lack of understanding of what wetlands can do and of how to effectively conduct pilot wetland studies. The impetus for this three-year wetland pilot study is to build an operational knowledge of treatment wetlands and to obtain a data set that can be used to redesign a full-scale wetland for produced water treatment.

Free-water surface (FWS) and subsurface flow (SSF) pilot wetlands were constructed. The wetlands were operated outdoors to test climatic influences and simulate real-world conditions. This paper presents and compares the design, construction, operation and data collection of FWS and SSF pilot wetlands. This treatment wetland paper covers the first two years of a three-year cooperative research and development agreement (CRADA) between DOE and ChevronTexaco. It includes water quality, troubleshooting, lessons learned and pilot operations with summer students. We will also explore the merit and associated effectiveness of treatment wetlands for small and large-scale oilfield operators.
The New Small-Drillhole Minipermeameter Probe for In-Situ Permeability Measurement
Authors: Dinwiddie C. L.
Published: December 2007

Laboratory measurement of permeability using a Hassler cell is the industry standard; however, consistently removing un-disturbed rock samples from friable outcrops is difficult. Al-though conventional surface-sealing minipermeameters have been developed as an alternative for permeability measure-ment, these devices suffer from difficulties in maintaining optimal forces on the tip-seal when dealing with outcrop ir-regularities in the field; outcrop weathering is also problem-atic. Because a reliable field method is needed for outcrop studies, this paper presents an innovative technique for meas-uring permeability in situ. The design of a new small-drillhole minipermeameter probe is discussed, as well as the accompa-nying analytical technique and the size and shape of the in-strument's averaging volume. Small diameter holes [i.e., 1.8 cm (0.7 in)] are drilled into an outcrop with a masonry drill, followed by drillhole vacuuming, probe insertion, seal expansion, gas injection, and calculation of the intrinsic permeabil-ity through measurement of the injection pressure, gas flow rate, and knowledge of the system geometry. Advantages of this approach are the elimination of questionable measure-ments from weathered outcrop surfaces, provision of a supe-rior sealing mechanism around the air injection zone, and the potential for permeability measurement at multiple depths below an outcrop surface. To date, data have been collected from three diverse porous media: upper and lower shoreface sandstone (Escalante, Utah), saprolitic soils (Clemson, South Carolina), and nonwelded tuff (Bishop, California). The probe has proved durable and robust, with a single probe being suffi-cient to make thousands of measurements in a variety of envi-ronments. Data quality supports the conclusion that the drillhole probe is a practical field instrument.
Four-Term Decomposition Techniques for a Faster Inversion of Induction Responses
Authors: Hardman Richard , Fanini Otto
Published: December 2007

We present a technique to decompose the computed response of an induction log and most other logs into four separate mathematical terms and suggest how these terms could be utilized in faster inversions. A challenging requirement for the interpretation of resistivity measurements is the availability of fast and accurate results presented in real-time in the logging unit for better casing decisions at the well site and the later formation evaluation. This challenge has taken new dimensions as formation evaluation targets have evolved from homogeneous to layered media, from vertical to deviated wells and from isotropic to anisotropic formations. The industry has previously addressed these interpretation challenges of induction measurements with two main approaches. These measurements are either deconvolved with filters or inverted with forward modeling in an attempt to obtain the true formation resistivity.

The inverse filter deconvolution approach based on Doll's vertical geometric factors (Doll 1949)1 is fast and suitable for thick layers and vertical wells (Barber 1985).2 Thin bed and dip effects impose serious limitations on the filters. Forward model based correction charts (Hardman and Shen 1987)3 are limited to three beds. In recent years geophysical data inversion has been increasingly used and an industry overview has been presented in the literature (Lines, editor 1988).4 The least square inversion method for induction data (Lin et al. 1984)5 has been also reviewed (Lines and Treitel 1984).6 Maximum likelihood and maximum entropy methods were developed in the fields of information theory (Shannon 1949)7 and imaging (Frieden 1972).8 Inversion of induction log data utilizing a maximum entropy technique (Dyos 19869, Freedman and Minerbo 199110) has been generalized to other resistivity data including multiple frequency and multiple array induction data. The main limitation of this iterative approach is the amount of time consumed by the derivatives computation (Barber et al. 1999).11

This paper describes a method utilizing the four terms resulting from the decomposition of the induction response (Hardman's patent application). This method enables the acceleration of resistivity inversion for vertical and deviated wells including traditional and newer multi-component induction data. The equations used by this method are shown and developed in this paper. The advantages of this method are clearly demonstrated for typical induction log interpretations utilizing inversion methods based on forward modeling. In a broader log context, the method is also relevant to the inversion of other logs that satisfy the diffusion (pulsed neutron logs), the Poisson (electric logs) and the wave equations (sonic logs).
Reserve Analysis for Multilayered Tight Gas Reservoirs
Authors: Cox Stuart A. , Stoltz Ronald P. , Wilson Allen S. , Sutton Robert P.
Published: December 2007

This paper presents an extension of the previous work by the authors1 to examine common reserve analysis techniques for non-communicating multilayered tight gas reservoirs. Tight gas reservoirs present unique challenges to the practicing reservoir engineer. One significant problem is estimating ultimate recoverable reserves for a tight gas reservoir. The extended time required to establish boundary dominated flow in the tight gas systems conflicts with the need to accurately estimate performance-based recoverable reserves early in the life of the well. One other complicating factor is the application of single layer solution techniques to the multilayered commingled completion.

Conceptual simulation cases are presented as a control set to test the accuracy of each analytical method. The simulation results are also used to test various methods of predicting the time required to establish boundary dominated flow in multi-layered, commingled completions. The two simulation cases under consideration are a uniform drainage area and a channel system. Well performance analysis is evaluated during both early time transient and late time boundary dominated flow. A field example is included comparing the results of each technique through time.
Water Vaporization in Gas Reservoirs
Authors: Zuluaga E. , Monsalve J. C.
Published: December 2007

Experiments have been performed to determine the rate of water vaporization in core samples at initial water saturation. The effect of pressure on rate of water vaporization has been studied. The experiments indicate that as pressure decreases from 2000 to 1000 psi, at constant temperature of 90°C, the rate of water vaporization increases from approximately 0.016 to 0.025 g/min. The effect of increase in temperature from 90°C to 100°C, at constant pressure of 1500 psi, is to increase the rate of water vaporization from 0.018 to 0.029 g/min. All the experiments were performed with the core samples at initial water saturation of 18%. As vaporization takes place, the brine remaining in the core sample becomes more concentrated. If concentration exceeds the critical supersaturation value, minerals will precipitate out into the formation. Additionally, the effect of salt precipitation on absolute permeability was determined. The results indicate that reduction in absolute permeability after the vaporization experiments ranges from approximately 14 to 30%.
Low Density, Lost Circulation Control Slurry Utilizing a Unique LCM Allows Successful, Single-Stage Cementing of Extremely Long Production Intervals in the Appalachian Basin
Authors: Mack David J. , Kendrick Daniel
Published: December 2007

The southern West Virginia area of the Appalachian Basin has numerous productive intervals within a single wellbore. The deepest of these is frequently the Rhinestreet member of the Lower Devonian Shale and the shallowest is the Maxton Sandstone or occasionally the Ravencliff Sandstone. The vertical distance between the top and bottom formations ranges between 3000 and 5000 feet.

In addition to the long completion interval, the lower portion of the Devonian Shale can be naturally fractured and exhibit a very low fracturing gradient of 0.4 psi/ft or less.

For a typical 6,500 ft Shale well with a 0.4 psi/ft fracturing gradient, a single stage cementing job covering 5000 ft, would require a conventional slurry with an equivalent density of 10.0 ppg. In an effort to achieve this much annular fill in the past, many cement slurries and techniques have been attempted, including foam cement and 2-stage operations. However, none of these measures routinely exhibited a high success rate at an acceptable cost.

This paper presents laboratory and field data for a unique, low density, high yield cement slurry that, when coupled with a unique, man-made lost circulation material, has routinely demonstrated 4000 ft to greater than 5000 ft of annular fill, at an acceptable cost in a single cementing stage.
Low Polymer Energized Fluid in the Arkoma Basin, Western Arkansas: A Case Study in the Gragg Field
Authors: Carman Paul S.
Published: December 2007

As with all mature petroleum fields, reservoir depletion becomes a factor, especially for wells drilled later in the life of the field. When the reservoir pressure becomes low, standard treatment fluids cannot be used effectively and other methods must be used to stimulate the reservoirs. The Arkoma Basin of Western Arkansas is no exception to this rule. This area of the basin is highly faulted and compartmentalized, which adds significantly to the reservoir complexity. Depending on well placement, there are several potential zones in each well exhibiting varying degrees of reservoir depletion.

The fracturing industry has gone through many technological advances over the years, and with these technological improvements have come many successes. Use of a low polymer energized fluid provides a good solution for these low reservoir-pressure reservoirs. These new style treatments provide faster cleanup, better flowback, better sand placement, and better production than conventional or previously utilized fracturing fluids.

The case studies will show that the low polymer energized fluid technique provides a positive response for these types of wells. Low polymer energized fluids can offer the qualities and properties to enhance completions and improve project and well economics.
Actual Field Data Show that Production Costs of Polymer Flooding can be Lower than Water Flooding
Authors: Wang Demin , Zhao Lanshui , Cheng Jiecheng , Wu Junzheng
Published: December 2007

Daqing Oil Field started industrial scale polymer (polyacrylamide) flooding in 1996. More than 3,000 wells are on polymer flood. The cumulative production by polymer flood is more than 400 million bbl, and annual production of year 2002 about 80 million bbl.

Actual field economic data show that the total cost (including depreciation) per bbl of polymer oil is about $9, the same as water flooding in the same area. Analysis of the data show that high incremental recovery (about 12% OOIP – original oil in place), high production rate (about 4 times that of water flooding) and low water oil ratio (a decrease of about 5 fold) are the main reasons polymer flooding obtained such good economic results.
An Integrated Model for the Design and Evaluation of Multiwell Hydraulic Fracture Treatments for Gas-Condensate Reservoirs
Authors: Valencia K. L. , Chen Z. , Rahman M. K. , Rahman S. S.
Published: December 2007

This paper presents a hydraulic fracture treatment design optimization scheme which integrates a hydraulic fracture geometry model, a production model and an economic model. The hydraulic fracture geometry model is used to determine the final fracture geometry and select the treatment parameters for a given stress and reservoir condition. Production from the treated well is estimated for pseudo-steady state condition using a model equivalent to a compositional simulator. A genetic-evolutionary optimization algorithm is used to obtain the optimum treatment parameters for maximum production or NPV. The integrated model has been used to investigate different field scenarios of a multiwell gas-condensate reservoir, including optimization of well locations and hydraulic fracture treatment parameters for any well type, achievement of target production and maximization of NPV with simultaneous minimization of the associated treatment costs.
Optimizing Oil Recovery of XJG Fields in South China Sea
Authors: Luo D. , Jiang Z. , Gutierrez J. , Schwab K. , Spotkaeff M.
Published: December 2007

China National Offshore Oil Corporation (CNOOC), Shell and Phillips China Inc. (PCI) are partners in the development of XJG oilfields located in the South China Sea. The XJG fields are considered to be in the mature phase and challenging PCI (the field operator) with lifting and surface treatment problems due to high water cuts, and the limited amount of slots available in the existing platforms for infill drilling.

A sandstone reservoir with average permeability over a Darcy and strong bottom water drive aquifer support is experiencing water breakthroughs from high permeable layers leaving hydrocarbons pockets behind. Typical completions include sand control devices such as gravel packs and Fracpack inside 9–5/8" casing.

The following list briefly summarizes the main challenges presented by the XJG fields at this stage: Total production close to the limit of surface treatment facilities: 550,000 BFPD.No more slots available for infill drilling, only 1 left reserved for an ERD well.Sand production aggravated due to wells producing at high water cuts.Overall oil recovery still below expected objectives.

PCI created a team including engineers from a service company working toward the common objective of "Maximizing Oil Recovery" in XJG fields making use of state of the art simulators, tools and innovative technologies specially tailored by technology centers to provide reliable answers in South China Sea completions and formation environments.

Reservoir modeling enabled the team to successfully identify remaining hydrocarbon areas in the fields. Resistivity measurements confirmed formation fluid saturations through the relatively large casing with high level of confidence. Reservoir modeling and resistivity measurements behind casing along with the innovative Geosteering tools and techniques helped plan and execute drilling new wells or sidetracking existing wells with high water cuts, effectively increasing oil rates and ultimate field oil recovery.

Encouraging results from this project along with other actions taken by PCI in the field have achieved an outstanding increase of 28 % in oil production of the new sidetracks while reducing the total amount of water at surface (in excess of 17,000 BWPD), saving PCI major expenditures on fluid treatment and/or upgrading platform facilities; benefiting from teamwork implementing innovative techniques in existing assets maximizing oil field recovery at effective cost.
Laboratory Study on MEOR After Polymer Flooding
Authors: Shi Mei , Wei Li , Liao Guangzhi , Han Peihui , Hou Zhaowei , Chen Xinghong , Wang Ying
Published: December 2007

Great advancement has been achieved with polymer flooding after water flooding to enhance oil recovery in Daqing oil field in China. By using polymer flooding, the oil recovery can be improved 12%, and the total oil production is 10 million tons per year in Daqing oil field. However, there is still about 50% remaining oil kept in oil-bearing formation after polymer flooding. This paper gives the method of Quarternary Oil Recovery by using MEOR succeeding a polymer flooding. In this paper, several kinds of bacteria that can grow with polymer and crude oil as the carbon source have been screened. These bacteria are different from that of growing with carbohydrate as the only carbon source used in MEOR before. Evaluation was made on the physiological and biochemical characteristics of the screened bacteria, the ability of their degrading oil and polymer, the ability of their producing bio-surfactant, and on the core displacement test. The results show that the light component and the rheological property of crude oil have been increased due to the action of the selected bacteria, the paraffin content, the gel content and the freezing point of crude oil have been decreased. Also, due to the action of the bacteria, the acid value of oil has been raised by 64.5 times and the initial boiling point has been reduced 80°C. Moreover, the Newtonian Index, Delta viscosity and EOR Index have been increased. Core displacement shows that oil recovery can be improved 5% or 13% by using MEOR or with the following ASP system respectively. All of the experiments can be repeated perfectly.
Analysis of Oil Recovery by Spontaneous Imbibition of Surfactant Solution
Authors: Babadagli T.
Published: December 2007

Depending on rock and oil type, lowered interfacial tension (IFT) by the addition of surfactant to brine may contribute to capillary imbibition recovery with the support of gravity drainage in naturally fractured reservoirs (NFR). This paper aims at identifying and analyzing the recovery mechanisms and performing up-scaling exercises for oil recovery from different rock types by the capillary (spontaneous) imbibition of surfactant solution.

Laboratory tests were performed using four different rock types that could possibly be the reservoir rock matrix of the NFRs (sandstone, limestone, dolomitic limestone and chalk). The sandstone sample was surface-coated to create a boundary condition causing only counter-current interaction. Wide variety of oils (light and heavy-crude oils, kerosene, and engine oil) was selected as the oleic phase. Different types (non-ionic and anionic) and concentrations of surfactants were used as the aqueous phase as well as the brine as a base case. The samples fully saturated with oil (Swi=0) were exposed to static capillary imbibition and the recovery was monitored against time. Some experiments on the chalks were repeated using pre-wet samples (Swi > 0) to clarify the changes in the capillary imbibition characteristics of the rock.

The changes (positive or negative) in the recovery rate and ultimate recovery compared to the brine imbibition were evaluated for the rock, surfactant and oil types. It was observed, for some rock samples, that the imbibition recovery by surfactant solution was strictly controlled by the concentration of the surfactant. On the other hand, the difference in the recovery rate and ultimate recovery between high and low IFT could be due not only to change in the IFT but also the change in the wettability and adsorption, which might vary with the rock type. This was also analyzed using the shape of the curves that indicates the strength of the capillarity on the recovery and the interaction type, i.e., co- or counter-current.

In addition to the above-mentioned qualitative analysis, the recovery curves were evaluated for up-scaling. Existing dimensionless scaling groups were tested. The scaling exercise helped identify whether the recovery is driven by gravity or capillary forces and clarify the interaction type, i.e., co-or counter-current or both. The ultimate recoveries were correlated to the Inverse Bond Number using twenty-five cases covering different combinations of four rock types, four oil and four surfactant samples. It was shown that the inclusion of the wettability factor would make the correlation more universal.
In-Situ Diagnosis of Inflow Behavior in Horizontal Wells
Authors: Bui T. D. , Vicencio O. A. , Sinha S. , Kalita R. , Jalali Y.
Published: December 2007

We investigate the concept of inverting certain wellbore measurements acquired during the normal process of production to infer the distribution of inflow along horizontal wells traversing heterogeneous formations. We consider measurements that are in principle feasible with fiber-optic sensors. Besides distributed temperature-sensing systems that have an established deployment record, we also examine wellbore pressure sensing at multiple points, which is nascent technology. One outcome of our analysis is broad requirements of such systems, such that they can be used in diagnosis of flow problems relevant to horizontal wells. We investigate this problem by modeling techniques encompassing multiple physical phenomena in the coupled wellbore-reservoir media (flow, thermal, and compositional), and associated inversion techniques (pressure and flowrate). We confirm the informative character of multipoint flowing pressure for liquid influx detection, liquid-liquid discrimination (under certain conditions), and also establish magnitudes of temperature effect associated with influx of gas-liquid mixtures. Results indicate the problem of two-phase influx in horizontal wells can be reasonably resolved with the method proposed in this study. Further work, however, is required to refine certain aspects of the methodology. We briefly address the implication of this methodology with respect to conventional methods, i.e., production logging.
An Innovative Approach To Integrate Fracture, Well Test and Production Data into Reservoir Models
Authors: Bahar Asnul , Ates Harun , Al-Deeb Maged H. , Salem Salem E. , Badaam Hussein , Linthorst Steef , Kelkar Mohan
Published: December 2007

This paper presents an innovative approach to integrate fracture, well test and production data into the static description of a reservoir model as an input to the flow simulation. The approach has been successfully implemented into a field study of a giant naturally fractured carbonate reservoir in the Middle East. This study was part of a full field integrated reservoir characterization and flow simulation project.

The main input available for this work includes matrix properties, fracture network, well test and production data. Stochastic models of matrix properties were generated using geostatistical methodology based on well logs, core, seismic data and geological interpretation. Fracture network was described in the reservoir as lineaments (fracture swarms) showing two major fracture trends. The network and its properties, i.e., fracture porosity and permeability, were generated by reconciling seismic, well logs, and dynamic data (well test and PLT).

The challenge of the study is to integrate all the input in an efficient and practical way to produce a consistent model between static and dynamic data. As a result, it is expected to reduce the history matching effort. This challenge was solved by an innovative iterative procedure between the static and dynamic models.

The static part consists of the calibration of model permeability to match the well test permeability. It is done by comparing their flow potentials, kh. In this analysis the dominant factor in controlling production at each well, either matrix or fracture, was determined. Based on the dominant factor, matrix or fracture permeability was modified accordingly. This way the changes in permeability are kept inline with the geological understanding of the field.

The dynamic part was carried out through a full field flow simulation to integrate production data. The flow simulation at this stage was used to match production capacity, i.e. to determine whether the given permeability (matrix and fracture) distribution is enough to produce the fluid at the specified pressure during the producing period of the well. The iteration is stopped once a reasonable production capacity match is obtained. In general, a good match was achieved within 3–4 iterations. The generated reservoir description is expected to substantially reduce the effort required to obtain a good history match.
In-Situ Diagnosis of Formation Characteristics in Horizontal Wells
Authors: Cui H. , Dong Y. , Kalita R. , Sinha S. , Jalali Y.
Published: December 2007

We present a method of estimating the distribution of permeability along the length of a liner-completed horizontal well from measurements of well flowing pressure at multiple points along the path of flow in the wellbore. We do not model the deployment mechanism of the sensors, although in principle this can be achieved with stinger completions.

The method applies to flow under constant-rate conditions and yields estimates of permeability along well trajectory in the principal directions normal to well path. Therefore, estimates of horizontal permeability perpendicular to well orientation and vertical permeability can be obtained for the gridblocks intersected by the well. Estimation accuracy, however, improves when the geometric mean of the normal permeabilities is obtained, as opposed to their individual values. This permeability group is what governs the influx into the wellbore. We neglect the effect of skin, but the method can be used to invert for a piecewise well index coefficient, that is proportional to the permeability group and inversely proportional to skin. Therefore, the method can generate the longitudinal profile of a parametric group that represents the quality of the formation and the integrity of completion.

The quality of the inversion is governed by the spatial density of measurements, accuracy of measurements, knowledge of wellbore hydraulics, and knowledge of the relative permeability characteristics of the formation. We obtain fair estimation of wellbore-gridblock permeability distribution for a five-node pressure configuration in a 2000 ft horizontal well experiencing 60 psi pressure drop (10,000 STB/day), given realistic bands of uncertainty associated with the governing parameters, including measurement drift, and errors in liner roughness, and relative permeability exponent. Also, the inversion can be rendered insensitive to knowledge of the reservoir permeability field through a far-field scaling technique. Therefore, good estimates of the near-wellbore permeability profile can be obtained with highly uncertain knowledge of the reservoir permeability field. This is important as the technique can be applied not only to early-time but also late-time data. We illustrate the application of the multipoint pressure method through a series of examples and discuss its potential as an interventionless method of well diagnosis, for estimation of both flux and permeability distribution in high-angle completions.
Implementation of Pressure Maintenance in Seria Field Using Limited Entry Fractured Water Injection
Authors: Sommerauer Gerald , Petersen Russel
Published: December 2007

The Seria Field is the largest oil field in Negara Brunei Darussalam. It straddles the coastline of Brunei about 120 km west from the capital Bandar Seri Begawan.

This paper discusses the novel application of Limited Entry Fractured Water Injection in two reservoirs in the Seria field as part of a larger implementation of secondary recovery and future efforts to increase economic oil production and ultimate recovery in the Seria field.

In 1999 a Produced Water Re-Injection (PWRI) Project was launched in Brunei Shell Petroleum (BSP) to re-use the produced water for re-pressurizing some of the depleted reservoirs of the Seria field. After having screened more than 400 reservoirs, it was decided to implement the PWRI pressure maintenance scheme as a first phase in two reservoir blocks. The paper will describe the implementation of the two pressure maintenance projects focusing on the completion of the water injectors. In describing the project the authors address the advantages and disadvantages of fractured injection compared to matrix injection and it’s impact on required surface facilities. A pseudo-three dimensional fracture propagation simulator has been used to evaluate the optimum fracture design for the injection wells. The simulation results show the advantages of a multi-frac design like smaller fracture dimensions, earlier pressure support of all layers, superior profile control, lower capital costs, and increased cumulative injection potential. Various completion options for the water injectors have been reviewed and the selected limited entry fractured water injection design described. Closing the paper the author describe the monitoring and surveillance program for the conformance control and fracture containment.

The presented novel completion design has the potential to revolutionize the completion of water injectors and the application of PWRI in general for water flooding projects.

The presented novel PWRI completion design is in the implementation stage and first results are expected in 2004.
Laboratory Investigations of First Contact Miscible Wag Displacement: The Effects of Wag Ratio and Flow Rate
Authors: Al-Shuraiqi H. S. , Muggeridge A. H. , Grattoni C. A.
Published: December 2007

Miscible WAG injection has been implemented in a number of oil fields around the world and there are a number of numerical studies investigating the effect of rate, gravity, slug size and heterogeneity on WAG performance. However there are very few laboratory studies of WAG displacement efficiency reported in the literature.

In this paper we report the results from a series of well-characterised WAG displacements through glass bead-packs. The aim of these experiments was to investigate the impact of first contact miscible WAG injection on oil recoveryto clarify the physical processes during displacements.to provide benchmark data-sets to validate reservoir simulations.

The use of bead-packs rather than cores enabled us to observe visually, for the first time to our knowledge, the fluid interactions during each WAG experiment.

A series of secondary, miscible WAG displacements were conducted at WAG ratios of 1:1, 4:1 and 1:4. These were performed at a range of flow rates to investigate the influence of capillary number on recovery efficiency. Their behaviour was compared with that obtained from simple miscible injection and waterflooding.

We show that recovery efficiency is a function of rate as well as WAG ratio. We also find that the water-oil and the water-solvent relative permeabilities are not the same for the analogue fluids used. This is despite the fact that the oil and solvent are first contact miscible. If this is true for reservoir fluids then clearly it will affect the prediction of WAG recovery efficiency.
The Slug Suppression System in Operation
Authors: Kovalev K. , Cruickshank A. , Purvis J.
Published: December 2007

In a flowline/riser system large liquid slugs and surges can be formed by operational changes or due to the flow conditions and physical characteristics of the flowline. These liquid slugs and gas surges may result in large oil and gas production losses when they arrive at a production platform. Slugging may cause high-level trips in separators and lead to unstable operation of topside facilities. The S3® Slug Suppression System provides a reliable solution to the slugging problem.

In 2002 Dril-Quip (Europe) Ltd delivered the first two commercial S3 units to Shell UK Exploration and Production (Shell Expro). The first unit was designed for the Otter development (TotalFinaElf) in the North Sea and installed on the North Cormorant platform (13 km flowline, 12" riser diameter, 18 bara separator pressure). In October 2002 the unit was successfully commissioned and is presently operating. The second system has been installed on the Brent Charlie platform in the North Sea, and is used for the Penguins development (64 km flowline, 14" riser diameter, 35 bara separator pressure). The unit was commissioned in January 2003. The commissioning results prove that the S3 can control liquid slugs and gas surges. The operational data shows that the control strategy is robust, flexible and capable of operating within all flow regimes encountered in the flowline.

The S3 system consists of a small separator with dynamically controlled valves at the gas and liquid outlets. The system is placed just upstream of the production separator. Shell Global Solutions developed the system with advanced control algorithms over the past years. The new technology was successfully tested at a test rig in Amsterdam and during field trials at the Shell Expro Gannet Alpha platform [1]. Operation of the S3 system was also extensively simulated with the dynamic numerical tools Traflow and Olga2000 and compared to other slug mitigation methods. An exclusive license was granted to Dril-Quip (Europe) Ltd to manufacture and supply the S3. Based on the field experience with the system, the S3 has proven to control/mitigate slugging.
The Role of the Annular Gap in Expandable Sand Screen Completions
Authors: Heiland J. , Cook J. , Johnson A. , Jeffryes B.
Published: December 2007

When an expandable sand screen is installed, the gap between the outside of the screen and the rock can vary from zero upwards. The gap is influenced by the state of the hole after drilling, subsequent logging or completion operations, and the natures of the screen and expansion process. This paper describes experiments and modelling undertaken to help understand and clarify the impact of the gap on the short- and long-term integrity of the completion.

Experiments measuring hole closure showed that the presence of a screen always improved hole stability relative to that of the open hole; this benefit was reduced when there was a significant annular gap. This conclusion was supported by rock deformation modelling, which showed that for a screen with relatively low radial stiffness, a very small or zero gap was best, while a stiff screen could tolerate a slightly larger gap, up to a few millimeters. In both cases this is to allow mobilization of rock strength through yielding. Gaps larger than this allow the rock to break up, potentially leading to point-loading or erosion problems. Modelling of the transport of liquid and sand showed that a smaller gap reduces annulus liquid velocity, ultimately to the point where sand transport (and potential erosion) no longer occurs. It also identified conditions that could compromise the long-tem integrity of the screen, such as blocked screen sections or regions of enlarged gap, which generate persistent regions of concentrated flow through the screen wall, again potentially leading to erosion problems.

The experiments were carried out using a newly developed bistable sand screen1. This has been designed to conform as closely as possible to the borehole wall, and have a very low deployment force, but the conclusions are equally applicable to other types of screen.