bluuebunny/crossref_metadata_2025 huggingface dataset:
Tortuosity Factors for Highly Tortuous Wells: A Practical Approach
Authors: Samuel G. Robello , Bharucha Kaiwan , Luo Yuejin
Published: December 2007

Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs and extended reach wells. When planning a well, wellpath modeling commonly generates smooth curves, whereas an actual well contains severe doglegs and other irregularities. Determining the tortuosity factors to apply in the well path is always a challenge during the planning phase. Presently no quantification method is available and field tests have shown that the present calculations gravely underestimate the drillstring torque and drag values for highly deviated, tortuous deep wells. Problems mostly occur when the drillstring lies in a strongly curved wellpath. In the long transitional region that covers most of the operational range in field applications, the conventional equations used for torque and drag calculation results in underprediction. Due to increased extended and steered wells the torque and drag calculations need correction to take care of the tortuous effects of the wellbore. This paper addresses the adverse impact of the torque and drag calculations in highly tortuous wells and presents an approach to calibrate the tortuosity factors whereby the accuracy of the calculations is enhanced. The methodology uses actual survey data and known surface hook loads for different operating conditions, such as tripping in, tripping out, and rotating off bottom, to arrive at appropriate friction factor values that can be used further in torque and drag calculations. Once the friction factors for both cased hole and open hole are determined, sensitivity analyses can be done on the planned survey. Appropriate tortuosity values are derived at by comparing predicted results with the field driller's data. This paper also describes four methods, Sine Wave, Random-Azimuth, Random-Inclination-Azimuth and helix used to calibrate the tortuosity factors that better represent the actual curved wellbore. The simple guidelines are presented along with two field examples from Gulf of Mexico. The simple, pragmatic approach provides a comprehensive framework for calibrating tortuosity values for complicated tortuous wellpaths.
Triaxial Creep Tests in Salt Applied in Drilling Through Thick Salt Layers in Campos Basin-Brazil
Authors: Maia C. A. , Poiate J. E. , Falcão J. L. , Coelho L. F. M.
Published: December 2007

The presence of salt structures in prospects for oil and gas exploration is, in itself, a factor that increases the probability of success due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipes and casing collapse have been reported by the industry when drilling through those salt layers.

Historically, in Campos Basin – Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90', the lack of a reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high costs and even loss of wells.

In this paper we present a methodology for mud weight and casing design and also to define the drilling strategies employed for drilling through thick salt layers. The numerical simulations to evaluate the creep behavior of salt submitted to high differential stresses and high temperatures were done through the applications of an in-house finite element code developed. To calibrate the model, triaxial creep tests in salt samples were performed to evaluate and isolate reological properties to represent its creep behavior under different differential stresses and temperatures. It was verified that numerical and experimental results matched and had a fine conformity.

A recent application of this methodology in a sub salt well in Campos Basin allowed us to drill the salt without a problem. Results obtained by numerical simulations were used to predict the evolution of the well closure with time for various mud weights and analyze several alternatives of casings capable of supporting salt creep. As a result, stuck pipe and casing collapse were avoided and drilling costs reduced.
Evaluation Methods for Suspended Solids and Produced Water as an Aid in Determining Effectiveness of Scale Control both Downhole and Topside
Authors: Jordan M. M. , Johnston C. J. , Robb M.
Published: December 2007

The formation of mineral scale (carbonate/sulphate/sulphide) within the near well bore; production tubing and topside process equipment has presented a challenge to the oil and gas industry for over 50 years. Chemical methods to control scale have been developed including scale squeeze treatments and continual chemical injection. A key factor to the success of such treatment is the understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. Evaluation of suspended solids in terms of amount, mineral type, composition and texture has been used along with brine chemistry to improve our understanding of the location of scale formation within production environments. This paper outlines the experimental methods developed and will site examples from the North Sea of the use of suspended solids analysis by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced brine. The combination of these methods has improved integrated scale management in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and topside scale control challenges vs. separation problems.

The publication of this method with clear examples of the value it can bring to an integrated scale management program for a field throughout its life cycle will benefit both emerging deep water (evaluation of placement) and more established oilfield operations (reducing chemical costs).
Study of Scale Inhibitor Reactions in Precipitation Squeeze Treatments
Authors: Tantayakom V. , Fogler H. S. , Chavadej S.
Published: December 2007

One of the most effective methods used in oilfield operations to prevent or limit scale formation is the use of precipitation squeeze treatments. A fundamental understanding of scale inhibitor precipitation is important in designing squeeze treatments in oilfield. Diethylentrilopentrakis (methylenephosphonic acid) (DTPMP) and Aminotri (methylenephosphonic acid) (ATMP), two scale inhibitors used in the petroleum industry were used as model inhibitors in this study. Inhibitor concentration, solution pH and the presence of salts in the produce fluids were found to have a significant impact on the placement of scale inhibitor and result in the formation of precipitates with markedly different properties. The amount of inhibitor precipitated decreases with the addition of Mg suggesting that the presence of Mg decreases the effectiveness of Ca-Inhibitor precipitation. A model of induction time was applied to inhibitor precipitation. Long induction times allow transport of the inhibitor fluids without inhibitor precipitation and damage to near-wellbore regions. The competitive reaction among the soluble salts in the formation water with the scale inhibitor was found to delay the precipitation rate of scale inhibitors. The nucleation kinetics of Ca-ATMP is accurately described by classical nucleation theory. The presence of different salts such as LiCl, NaCl, KCl and MgCl2 in solution was found to increase the surface free energies, thereby delaying the inhibitor nucleation and growth.
Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria
Authors: Kuijvenhoven C. , Bostock A. , Chappell D. , Noirot J. C. , Khan A.
Published: December 2007

The Bonga field located in deep water off the Nigerian coast needs pressure support to effectively recover the hydrocarbons. The strategy is to inject 300k bwpd seawater from the start of oil production. During the field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring, and that mitigation would be necessary.

Initial data gathering indicated that the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm(v) in the gas phase. Initially nano-filtration to reduce the sulphate level in the seawater was identified to mitigate reservoir souring but due to the high CAPEX costs it was dropped and as there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H2S with sour service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50 ppm(v) H2S.

As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S development. However, to date the main application for nitrate had been the reduction of H2S in already sour fields and the experience for the use of nitrate from the start of the water injection scheme was limited.

This paper presents a detailed evaluation of the potential for reservoir souring due to biogenic reservoir souring in the Bonga field, and work done to predict H2S levels. The paper will also focus on the selection of nitrate as a mitigation method.
Deep Downhole Chemical Injection on BP-Operated Miller: Experience and Learning
Authors: Wylde J. J. , Williams G. D. M. , Careil F. , Webb P. , Morris A.
Published: December 2007

The BP operated Miller field poses a unique chemical challenge as it has arguably the harshest oilfield scaling regime in the North Sea, if not the world. An average of 3-4 squeeze treatments per week are performed across the online wells creating tremendous operational, chemical and logistical challenges. This produces the ideal environment to evaluate new technologies and engineering solutions in an attempt to increase the wells' overall efficiency.

Deep downhole chemical injection (DDHCI) was installed on well A26/08 and brought online during July 2003. The Miller DDHCI is unique to the industry as it allows the injection of a scale inhibitor at the perforations via a tail pipe essentially protecting the whole of the tubing from scale deposition. This approach has the potential to reduce the need for additional scale control via squeeze treatments.

Much emphasis has been placed on the efficiency of scale protection DDHCI offers. A year of flowing the well under the protection of the continuous injection chemical has yielded much information about the nature of the chemical delivery and inhibitor efficiency. Much has also been learnt about the pumping hardware required to ensure continued performance. Further information has been provided by two intensive sampling exercises which have allowed independent analysis for the squeeze chemicals and the injected chemical.
Recovery of Oil from Drilled Cuttings by Liquefied Gas Extraction
Authors: Seaton S. , Hall J.
Published: December 2007

It has long been accepted that non-aqueous invert emulsion drilling fluids provide improved drilling performance compared to traditional water-based systems. Use of diesel, mineral oil, and more recently, synthetic materials such as olefins and paraffins as base fluids has gained global acceptance. However, the disposal of these materials and associated drill cuttings can generate environmental concerns. The capability to remove oil or synthetic oil from the cuttings before disposal can significantly reduce the long-term environmental effects of disposal. In addition, effective recovery of costly synthetic fluids could improve the overall economics of drilling.

This paper summarizes research efforts into development of a technique that uses liquefied hydrocarbon gases as solvents to extract oil from cuttings. The laboratory data presented shows that a wide variety of fluids can be efficiently recovered from cuttings. Residual oil on cuttings levels can be reduced to concentrations exceeding the standards typically required for disposal or discharge, with no thermal energy requirements and recycling of the solvent phase and recovered fluid. Risk assessments indicate that the technique can be safely applied at both onshore and offshore operations.
West Seno Deepwater Development Case History–Production Chemistry
Authors: Gallup D. L. , Smith P. C. , Star J. F. , Hamilton S.
Published: December 2007

The West Seno field is located in the Makassar Strait PSC offshore East Kalimantan, Indonesia about 60 km offshore in ~3,200 ft of water. Field development consists of a tension leg platform (TLP), a floating production unit (FPU), and two export pipelines tied back to existing onshore infrastructure. Production commenced in August 2003, and Phase 1 of the project has now ramped up to over 45,000 BOEPD.

The field presents a number of production chemistry and flow assurance challenges, the most serious of which is an unusual emulsion. Organic acids in West Seno crude oils react with bicarbonate rich produced waters to form sodium and other metal carboxylates. These metal carboxylates are "soaps", which tend to linger at water/oil interfaces and afford highly stabilized brine-in-oil ‘forward’ emulsions. Conceptually, soap-stabilized emulsions should be easy to break, as one simply adds a demulsifier to reverse the soapforming reaction and allowing the phases to separate. Unfortunately, the emulsions are constantly undergoing shear, by various items of standard production process equipment, helping to re-emulsify partially separated fluids. Furthermore, in the deepwater environment, produced fluids tend to cool significantly, thereby losing the benefit of heat-induced demulsification and causing waxes to precipitate. Also, fine solids (formation fines, residual drilling mud solids, etc.) typically accompany production, further adding to emulsion stability. Although acid demulsifiers have been successfully applied at West Seno, due to the complex nature of the emulsions with multiple stabilizers identified, a finite residence time is still needed for phase separation, which creates a potential production bottleneck. Emulsions must not be over-treated since injection of acidic chemical induces corrosion, and the phosphoric acid portion of the demulsifier reacts with calcium in the brine to form hydroxyapatite and vivianite/polyphosphate scale solids.

To destabilize the emulsions it is important to dehydrate the oil as early as possible with heating, minimize shearing and reduce the introduction of solids to the production stream by insuring an efficient mud displacement prior to well completion. Desander hydrocyclones are used on the FPU upstream of deoilers, and regular sand jetting of the main separator is necessary. Other important production chemistry/flow assurance issues that are being addressed include: gas hydrate inhibition,produced water treatment with reverse emulsion breakers, flocculants and solids wetting agents,microbiological control in FPU "off spec oil" and off spec water" surge tanks, andcompatibility of treatment chemicals and adverse effects on the soap emulsion.
Evaluation of the Effect of the Water Formation Salinity in the Performance of Gels for Water Shutoff
Authors: Llamedo M. A. , Fernández I. J. , Pérez D. L. , Rauseo O. , Valero E. , Espinoza J.
Published: December 2007

In this work a gel of an acrylamide based polymer crosslinked with organic reagents was studied. This gelling system was one of the commonly used in water conformance treatments. Once formed in bottle tests the gel was placed in contact in several proportions with water of various salinities. The tests where carried out at 266°F, and the changes were registered as a function of time. It was found that the gel swelled until a constant final volume. This value depende the difference between the salinity of the water used to prepare the gel and the added water. The performance of this gel in porous media was evaluated by coreflood experiments in Berea sandstone at 266°F with water prepared with the same compositions evaluated in the bottle tests. The results indicated that the RRF values are lower if the salinity of the reservoir water is similar to water salinity used to prepare the gelling mixture; while the Residual Resistance Factor (RRF) increased if the salinity of the reservoir water was much higher than the salinity of the preparation water.

These findings show that it is important to take into account the difference between the water salinity used to prepare the gelling system and the water reservoir in the design of water conformance treatments with polymeric gels.
Effective Chemistries to Control SRB, H2S and FexSy Problems
Authors: Dickinson A. , Peck G. , Arnold B.
Published: December 2007

Sulfate reducing bacteria (SRB) exist in many oilfield production systems. Their metabolic by-product, hydrogen sulfide (H2S), is corrosive and also combines with iron ions to form iron sulfide (FexSy) solids. The corrosive and plugging effects of these materials can severely impact operations and costs of a water injection system. Their control can present a significant challenge for the system operator.

This paper reviews the field performance of three different chemistries to control SRB, associated H2S, and FexSy solids. These chemistries include a mixed amine biocide, acrolein, and anthraquinone. Each chemical is applied to a specific part of the oilfield production system to effectively treat for biogenic sulfides. These locations include: at the producing wells, at the waterplant and downstream water injection system and a slop handling system. Each product was selected for its unique chemical properties that best resolved the specific field problems.

The results of this study indicate the following:

Periodic batch treatments of numerous artificial lift wells with a mixed amine biocide reduced the sulfides in the mixed produced fluids entering the waterplant inlet by 90%. An acrolein batch treatment program reduced total suspended solids levels at the waterplant outlet by 87% and improved other water quality parameters in the downstream injection system. Anthraquinone batch treatments into the slop handling system reduced sulfide levels by 95%.
Improving Injector Efficiency Using Streamline Simulation: A Case Study of Waterflooding in Saudi Arabia
Authors: Ghori S. G. , Jilani S. Z. , Vohra I. R. , Lin C.
Published: December 2007

The 3-D streamline simulation approach is complementary to finite difference simulation techniques. One of the main advantages of streamline simulation is its ability to display paths of fluid flow and to calculate rate allocation factors. These capabilities have been utilized to improve operating and development plans for a water-flood project.

An incremental development plan for a Saudi Arabian carbonate reservoir that included the drilling of several horizontal injection/production wells is discussed in this paper. A few wells had already been drilled at the start of this study. The main objectives of this study were to improve well placement and injection rates using streamline simulation.

During the course of the study a few limitations of the streamline simulator have been encountered, highlighted, and discussed. The results showed that streamline simulation is still in the development stage in highly compressible systems. It is tricky to follow field/group rate targets and limits along with the individual well rate targets in prediction mode.

Prior to the optimization phase of the study, the streamline simulator was successfully applied to reproduce the historical performance of the reservoir during primary depletion in the absence of any water injection.

Valuable information was obtained from streamline simulation; a) distribution of injected water to associated producers, b) water loss to the aquifer, c) percentage of oil produced due to each supporting injector, and d) amount of water cut attributable to each supporting injector.

Quality indicators were generated to gauge injection efficiency for each well using plots of injection rate vs. offset oil/liquid production rate. Relatively poor performance injectors were identified from this plot. Injection allocation rates and injector drilling locations were then modified through a series of simulations to improve their efficiency. This led to an improved injection pattern in the studied reservoir.
Two Different Water Shutoff Applications in a Poorly Consolidated Sandstone Reservoir with Strong Waterdrive
Authors: Prado M. , Palencia J. , Reyna M. , Fernández I. , Espinoza J. , Rauseo O.
Published: December 2007

This paper describes the design, operation and results of two different water shut-off applications in a field located in Southern Venezuela. The production mechanism of the main reservoirs of the studied field is strong water drive. The presence of the active aquifer, the geological complexity and the high drawdown produced by the electric submersible pumps, it has abruptly increased the water-oil ratio causing premature shutting.

The limitations of the traditional water shut-off applications in this field are the slotted liners gravel pack completion of the wells, the high formation permeability and the presence of caverns in the near wellbore due to sand production. A project was proposed to evaluate the gel technology, including the diagnosis of the high water production source and the design of applications to overcome these limitations.

Two mayor causes were detected, water channeling through high permeability strakes at the top of the reservoir where thin shale barriers are present; and rapid coning at the base, where the sand has a higher vertical permeability and the water-oil contact is present.

According to this, two different applications were designed and successfully evaluated in three wells of the field, two of them correctives and the other preventive. Relevant aspects of the design are the use of an elastic gel system of high consistency with easily controlled gelling times; and the use of placement techniques to guarantee the seal of offensive zones and the protection of the productive ones. In the corrective treatments the gelant was injected using mechanical isolation and the total volume was pumped in two batches, while dual injection was carried out in the preventive application. A reduction of 3000 barrels per day of water production was obtained, as well as a substantial increase in the productive life of the three wells.
Development and Field Application of a High Performance, Unstructured Simulator with Parallel Capability
Authors: Shiralkar G. S. , Fleming G. C. , Watts J. W. , Wong T. W. , Coats B. K. , Mossbarger R. , Robbana E. , Batten A. H.
Published: December 2007

We present the development and field application of a high performance, unstructured simulator with parallel capability. The simulator integrates the subsurface with the surface network model. An earlier paper1 described the integrated surface model. This paper emphasizes the subsurface model and multi-field application.

Object oriented concepts are used to gain flexibility, using efficient data structures to retain performance. The reservoir computational domain is composed of "Grids" and inter-grid connection structures that form the basis for parallelization. The Grids are ensembles of cells that are unstructured in general, and need not be contiguous.

Besides unstructured (PEBI) grid simulation capability, this framework also forms the basis for simulating multiple, independently gridded reservoirs, with shared surface facilities, an important business problem. Earlier multireservoir workflows use LGR's in a fixed grid, making changes like adding a new reservoir difficult. Alternately, they use multiple processors with imperfect resolution of inter-reservoir coupling. In this paper, use of grid objects greatly facilitates the workflow; reservoir grids can be easily added or changed. Simultaneous solution of multi-reservoir and facilities system ensures consistent coupling throughout.
Kinetics and Equilibria of Calcium Lignosulfonate Adsorption and Desorption onto Limestone
Authors: Bai B. , Grigg R. B.
Published: December 2007

Equilibria and kinetics are two basic ingredients for the proper understanding of adsorption and desorption processes between surfactants and rocks. The adsorption and desorption of calcium lignosulfonate (CLS), commonly used as a sacrificial agent in surfactant-based EOR processes, has been studied.

Kinetic results showed that adsorption and desorption are both time-dependent, not instant. Both adsorption and desorption were characterized by a biphasic pattern: a fast step followed by a slow step. Apparent adsorption and desorption rate coefficients were determined by a second-order kinetic model. Desorption is a much slower process than adsorption. Desorption is an un-equilibrium process under normal reservoir flow rate conditions.

Equilibrium results show that CLS adsorption and desorption onto limestone can be described well by the Langmuir isotherm over the tested CLS concentration range, and that increasing concentration increases adsorption density. There is significant hysteresis between CLS adsorption and desorption isotherms. Increasing flow rate slightly decreased CLS equilibrium adsorption. Increasing both NaCl and CaCl2 concentrations increased adsorption density; however, CaCl2 had a much greater impact on the adsorption. Increasing pH decreased CLS adsorption onto limestone. The reasons for the effects of the different factors are elucidated in this paper.
Surfactants as Flow Improvers in Water Injection
Authors: Oskarsson H. , Uneback I. , Hellsten M.
Published: December 2007

In many cases it is desirable to increase the flow of injection water when an oil well deteriorates. It is very costly in offshore operation to lay down an additional water pipe to the injection site. Flow improvers for the injection water will thus be the most cost-effective way to increase the flow rate. During the last years water-soluble polymers have also been applied for this purpose. These drag-reducing polymers are however only slowly biodegraded which has been an incentive for the development of readily biodegradable surfactants as flow improvers for injection water.

A combination of a zwitterionic and an anionic surfactant has been tested in a 5.5 inch, 700 m long flow loop containing sulphate brine with salinity similar to sea water. A drag reduction between 75 and 80% was achieved with 200 ppm of the surfactant blend at an average velocity of 1.9 m/s and between 50 and 55% at 2.9 m/s. Due to the self-healing properties of the drag-reducing structures formed by surfactants, these may be added before the pump section - contrary to polymers which are permanently destroyed by high shear forces.
Design and Deployment of Maximum Reservoir Contact Wells With Smart Completions in the Development of a Carbonate Reservoir
Authors: Afaleg N. I. , Pham T. R. , Al-Otaibi U. F. , Amos S. W. , Sarda S.
Published: December 2007

This paper presents an in depth study for a field-wide application of Maximum Reservoir Contact (MRC) wells along with smart well completions complemented by openhole expandable tubular to develop Haradh Increment-3, the southernmost area of the greater Ghawar Field. The reservoir represents a heterogeneous matrix permeability background, with geological discontinuities such as faults, fractures, and stratiform high permeability streaks. An MRC is a multi-lateral horizontal well with more than 5 km. of total contact with the reservoir rock(1,2). This paper illustrates how an MRC well with smart completion was designed with objectives for higher productivity, better pressure transfer between laterals, delay in water encroachment by down hole control, and higher cumulative production. The design was based on highly detailed dual porosity and dual permeability cross-sectional, sector and full field simulation models in addition to field trials.
Interwell Tracer Tests: Lessons Learned From Past Field Studies
Authors: Du Y. , Guan L.
Published: December 2007

The application of interwell tracer tests is becoming increasingly important to the petroleum industry. Interwell tracer tests, as a proven and efficient tool, have been used to investigate reservoir flow performance and reservoir properties that control gas and water displacement processes. Tracer data have been used to reduce uncertainties attributed to well-to-well communications, vertical and horizontal flow, and residual oil saturation.

This paper describes the development of interwell tracer tests in the petroleum industry, from the first qualitative tracer test in the 1950s to the latest quantitative tracer test in the 2000s. The results of our study indicate that poor sampling is the most frequently encountered problem that leads to a failure tracer test and only a small number of interwell tracer tests have employed the advanced numerical modeling methods to analyze the test data. In addition, the interwell tracer tests in the petroleum industry are not well studied as hydrology industry. Therefore, the interwell tracer tests interpretation methods deserve to be paid more attention, so that petroleum engineers can take better advantage of the costly interwell tracer tests.
Asphaltene Adsorption Isotherm in the Pores of Reservoir Rock Cores
Authors: Alkafeef S. F. , Smith A. L.
Published: December 2007

New data relating to the adsorption of asphaltenes on rock pore surfaces are reported. The data were obtained from the measurements of the electrokinetic potential of several different sandstone core samples with asphaltenic oils. The adsorption of asphaltene is accompanied by a numerical reduction in the (negative) surface potential of the pore walls, eventually stabilizing at a small positive potential, attributed to the asphaltene itself.

After increasing to around 30% of the pore radius, the asphaltene adsorbed layer thickness stopped growing either with time or with concentration of asphaltene in the flowing liquid. This behaviour is attributed to the effect on the disjoining pressure across the adsorbed layer described by Derjaguin and Churaev1.

Alternative hypotheses involving asphaltene adsorption isotherm have been investigated. A theoretical treatment advanced describing particle adsorption in the same terms as molecular adsorption and the Langmuir isotherm, with the free energy of asphaltene adsorption on the rock surface (modeled on silica), calculated on the basis of van der Waals attraction. Acceptable agreement was obtained with the electrokinetic measurements.
Application of Adaptive Wavelets To Improve Computational Performance of Kriging
Authors: Yuwono I. P. , Susanto A. , Soesianto K. , Tran T. T.
Published: December 2007

Kriging is a geostatistical estimation tool that has widespread applications in environmental, hydrologie, and petroleum applications. Kriging requires solution of a linear system of equations, often called the kriging or normal equations. The speed of this matrix inversion is dependent on the size of the kriging system; more input data results in larger kriging matrix which takes longer to invert.

Wavelet transform, due to its compact support and orthogonality property of the basis functions, holds some promise to improve computational performance of kriging. An interesting property of wavelet is that the wavelet transform of a dense matrix gives rise to a sparse matrix. The CPU cost of inverting the transformed sparse matrix can be much less than that for the original dense matrix, depending on the degree of sparsity and the bandwidth of the transformed matrix.

This paper presents a study on the application of wavelet transform to improve the computational performance of kriging. Conventional "off-the-shelf wavelets and wavelets derived from an adaptive process were used and their relative performances are documented.
Fit-for-Purpose Production Logging: Memory or Real-Time?
Authors: Al-Muthana A. S. , Ma S. , Al-Hajari A. A. , Aboelnaga S.
Published: December 2007

Memory production logging (M_PL) with slick-line offers some advantages over real-time production logging with electric line which include simpler control or management of well pressure, a smaller footprint for operating equipment, and in general, less cost. Thus, it is inimitable for wells with high flowing wellhead pressure such as deep gas wells and wells with rig-up space restrictions such as small offshore platforms and/or jackets. However, one of the main drawbacks for M_PL is that its data can't be quality controlled in real-time, which is important if real-time decisions need to be made while logging. Therefore, running M_PL is a fit-for-purpose choice and well selection and job planning is critical for the success of running M_PL jobs.

In this study, five field examples of M_PL are presented and compared with well data. These examples include onshore and offshore wells, oil/water and deep gas wells, wells with cased-hole and open-hole completions, and vertical and deviated wells. Recommendations and guidelines of running M_PL are presented.
Souring of Reservoirs by Bacterial Activity During Seawater Waterflooding
Authors: Maxwell S. , Spark I.
Published: December 2007

Waterflooding with seawater for pressure support is to be employed in many of the deepwater Gulf of Mexico fields. Seawater flooding has been employed in the North Sea oilfields for over thirty years and, therefore, this region serves as a valuable source of case histories of the problems that can be encountered. It is now accepted that due to inadequate control of sulfate-reducing bacteria (SRB) the majority of the North Sea seawater floods resulted in souring of the reservoir.

In some cases, hydrogen sulfide concentrations in the production wells have risen to the point where either the well has had to be shut-in or sulfide scavenging chemicals have had to be applied in order to prevent excessive corrosion. Where souring was not predicted, some production systems have had to be upgraded for sour service materials. These remedial actions have resulted in very significant unplanned costs. Although there is no formal published economic data, it is clear that over the history of the North Sea, the cost of lost production and remedial action has been $ 100's millions.

This paper reviews the North Sea experience and discusses the models developed in an attempt to predict reservoir souring. The paper discusses the application of chemical biocides attempted to kill the SRB; the injection of nitrate to stimulate other bacterial populations to compete with the SRB for essential nutrients; and the potential for sulfate removal technologies to reduce sulfate and minimise sulfide production. A strategy for the development of future models to help predict and avoid reservoir souring in future seawater floods is also discussed.
Prediction of Scale Inhibitor Squeeze and Return in Calcite-Bearing Formation
Authors: Kan A. T. , Fu G. , Tomson M. B.
Published: December 2007

Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction. In this study, four common oil field inhibitors (three phosphonates and one polyacrylate) are compared in totally contained squeeze simulation using calcite, a calcite-rich chalk, a calcite and clay containing formation material and a sandstone formation material with predominantly quartz and minimum calcite. Similar inhibitor return behavior was observed in both calcite-rich and low calcite rock, suggesting that calcite is the primary solid responsible for phosphonate retention and clay plays a secondary role in phosphonate retention. The retention of the polymer is much lower than phosphonates. The data show that BHPMP provides the highest squeeze life at MIC > 50 mg/L. DHPMP is the preferred inhibitor at MIC between 1 and 50 mg/L and NTMP is the preferred inhibitor at MIC < 0.3 mg/L. With DTPMP and BHPMP we have found that it is possible to predictably obtain a long and high concentration of inhibitor return. This is exactly what is often needed during, e.g., seawater breakthrough to control barite scale formation. This kind of predictable treatment should be valuable for onshore wells that produce from multiple incompatible zones and to offshore flow assurance issues wherein it is critical to have the ability to control scale during seawater breakthrough. We are presently incorporating these findings into the software for squeeze design, SqueezeSoftPitzer and doing the necessary testing to be certain of the predictability of variations in brine composition and T, P, and TDS.
Microemulsion Reduces Adsorption and Emulsion Tendencies in Bradford and Speechley Sandstone Formations
Authors: Paktinat J. , Pinkhouse J. , Williams C. , Penny G. S.
Published: December 2007

The primary purpose of nonionic surfactants used in well stimulation is to reduce surface tension, contact angle and emulsion tendencies. However, many of these chemicals adsorb rapidly into the surface of the sandstone formation, reducing their effectiveness in reservoir treatments.

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

Field data collected from Bradford and Speechley sandstone formations confirms experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional non-emulsifying surfactant treatments. These investigations and presented field data may be used to optimize chemical treatments. The primary objectives of this study are focused to include: Comparison studies of the microemulsion system with conventional ethoxylated surfactants commonly used in the oilfield to determine their adsorption properties into the proppant pack, surface tension and water recovery.Experimental data comparing effectiveness of conventional surfactants and microemulsion in non-emulsification and regain permeability tests.Present case studies where microemulsion treatments have improved water recoveries in treated gas wells.

This paper describes laboratory methods and case histories supporting this investigation. Furthermore, field data collected from several gas wells stimulated in the Bradford and Speechley formations illustrates the microemulsion fluid exhibiting an advantage over the conventional surfactant treatments when water recovery and increased well productivity are of concern to the operator.
Asphaltenes Pipeline Cleanout: A Horizontal Challenge for Coiled Tubing
Authors: Torres C. A. , Treint F. , Alonso C. , Milne A. , Lecomte A.
Published: December 2007

Crude produced in the North of Monagas Estate, East Venezuela, has a high asphaltene content, which comes out of solution in both the wellbore tubulars and pipeline. This can eventually lead to complete plugging of the pipeline. This increases the cost of maintaining production because of the need to periodically remove these organic deposits. In a specific case, 9 km of 8-5/8-in. outside diameter (OD) production pipeline was successfully cleaned out using 2-in. OD coiled-tubing (CT) to regain pipeline production. As there is limited literature or documentation on the use of CT for this specific application, the operator and the service company established a joint team to do the feasibility study and engineering. Some of the key points were; the design of a frame to lay down the injector head, define the entry points along the pipeline, the selection of the bottomhole assembly (BHA), and fluids to use. Other issues were the measurement of stresses (push/pull) on the CT so that the CT could be run as far as possible in the pipeline without damaging either the CT or the pipeline. The pipeline was successfully cleaned, the CT being run seven times from five different entry points in the pipeline. This resulted in savings of USD 1 million for the operator and significantly reduced the time to recover normal production in the pipeline.
Mexico's Influence in the World's Oil and Gas Supply and Demand
Authors: Rojas S. , Saputelli L. , Economides M.
Published: December 2007

As of the end of 2004, the share of natural gas in the total world energy demand was approximately 23% having surpassed coal in 2002 and, for the first time, becoming the number two fuel behind oil. Buoyant estimates suggest that the natural gas market share will increase dramatically by the year 2020.

Natural gas demand will be greatly influenced by the developed economies, namely the United States, Japan and Europe, the emerging energy super-consumer China and the rapidly developing economies of some of the world's most populous nations such as Brazil and Mexico.

This paper focuses on Mexico. Mexico's trillion-dollar economy has resulted in its becoming the second largest US trading partner. The purpose of this work is to generate a framework wherein Mexico can develop its internal energy market and still be a strategic partner for energy with the United States. Strategies such as (a) interconnecting pipelines with the United States, (b) exporting LNG, (c) increasing the gas-to-oil ratio from its existing portfolio, and (d) increasing dry-gas exploration efforts are some of the different options that are considered and outlined in this work.
How Minimum Inhibitor Concentration (MIC) and Sub-MIC Concentrations Affect Bulk Precipitation and Surface Scaling Rates
Authors: Graham A. L. , Boak L. S. , Neville A. , Sorbie K. S.
Published: December 2007

Conventional testing of scale inhibitors (SI) usually focuses only on the inhibition of bulk depositional processes, e.g. in jar tests of inhibition efficiency. In previous work, we have extended the study of inhibition efficiency to examine both bulk and surface depositional processes and their inhibition using scale inhibitors. Where the minimum inhibitor concentration (MIC) is well exceeded, both bulk and surface scaling are prevented. However, we have demonstrated that the presence of an inhibitor, at levels marginally below the MIC, actually enhances surface scale growth over a range of temperatures typically encountered in the production system. Where this precise concentration lies with respect to the MIC is not generally known for scaling systems and it is therefore difficult to predict where potential problems with sub-MIC scale inhibitor levels would occur.

An experimental programme has been conducted to assess the efficiency of PPCA in inhibiting barium sulphate scale formation in the bulk solution and on a metal surface over a range of concentrations and test temperatures. The concentration range tested was chosen (a) to allow identification of the MIC at which both surface and bulk scale formation is controlled and, (b) to establish where potential problems with enhanced surface scaling arise at sub-MIC levels. The results obtained from this study have allowed trends in surface and bulk inhibition to be established and the region of sub-MIC concentrations where surface scaling is enhanced to be identified for three temperatures. We summarise our results using some simple schematic models of the bulk and surface scaling regimes and the corresponding inhibition process.
Brine and Permeability Effects on Crosslinked Fluid-Loss Pill Filter-Cake Formation
Authors: Vollmer D. P. , Lejeune B. E.
Published: December 2007

During completion and workover for the recovery of oil and gas, fluid loss pills are used to control completion brine losses to the formation. Basically, the operator has three types of fluid loss pills to choose. They are linear water soluble polymers like hydroxy ethylcellose (HEC), solids laden, and the most recent crosslinked pills. Since both HEC and crosslinked pills are considered solids free, crosslinked pills are more effective on higher permeability formations by the formation of a polymer filter cake. However, little work has been done to define the permeability limit for these crosslinked pills and when an operator should use a solids laden pill instead of a crosslinked one. Also, the brine type effects the overall efficacy of the fluid loss pill. Therefore, lab tests were conducted to address these issues by evaluating a crosslinked zirconium carboxy methyl hydroxy ethyl cellulose (CMHEC) pill. The tests showed that as the calcium halide increases the ability for filter cake formation for this crosslink pill decreases with permeability. For example, for crosslinked CMHEC in water at 180°F, the limit is less than 20 Darcy (60 micron) but in a 14.2 ppg calcium bromide solution; the limit is less than 2 Darcy (10 micron). Other variables like pH and temperature are discussed to provide guidelines.
Chemical Demulsifier Development Based on Critical Electric Field Measurements
Authors: Beetge J. H. , Horne B. O.
Published: December 2007

Resolution of water and oil emulsions is critical to the oil field industry. A wide variety of undesirable emulsions are formed during the production, handling and processing of crude oil. Although various methods are used, dehydration of crude oils is mostly achieved by gravitational sedimentation, normally at elevated temperatures and with the addition of chemical demulsifiers.

The quantitative evaluation of emulsion stability by a Critical Electric Field (CEF) technique was developed to play a significant role in chemical demulsifier research. It was found that the CEF technique is not only useful in the evaluation of water-in-oil emulsion stability, but also in studying the mechanisms of stabilization as well as demulsification.

A method was developed to study the mechanism of emulsion stabilization in terms of flocculation and coalescence behavior of a crude oil emulsion. The effect of chemical demulsifiers on emulsion stability was evaluated in terms of the method developed in this study. By following this approach, it is possible to determine the relative amount of energy required for both flocculation as well as coalescence, in the presence of a chemical demulsifier.
H2S Scavengers for Non-Aqueous Systems
Authors: Buller J. , Carpenter J. F.
Published: December 2007

Hydrogen Sulfide (H2S) is problematic in oilfield systems because of its high toxicity and corrosive nature. There are a number of technologies available to remediate sour production streams containing water. However, technologies to effectively and quickly scavenge water-deficient, oil systems are limited.

In this paper we review the properties of a family of new, fast-acting, oil-soluble H2S scavengers based on carboxylates of zinc and iron. Laboratory and field performance data are presented. This technology's efficacy is demonstrated in a plant trial treating a 1200 ppm hydrogen sulfide contaminated oil-stream. A range of competing oil- and water-soluble scavengers was shown to be less effective under these conditions.