bluuebunny/crossref_metadata_2025 huggingface dataset:
Three-Dimensional Permeability Utilizing a New Gas-Spot Permeameter
Authors: Belhaj H. A. , Mousavizadegan S. H. , Ma F. , Islam M. R.
Published: December 2007

Permeability, a major reservoir property that reservoir engineers strive to measure as accurately as possible, is nevertheless always measured indirectly, by estimation, either through well-testing or specific logging tools and techniques. Permeability measurement utilizing reservoir rock samples does not necessarily guarantee accurate results, as fluid saturation of rock samples may change dramatically due to stresses and pore pressure changes take place during coring and transportation of samples to the laboratory for testing. In attempting to extrapolate fluid flow behavior in the reservoir from such samples, tremendous efforts have been directed up to now towards producing useful meanings of horizontal, vertical and directional permeabilities.

This paper introduces a new permeability measurement approach that brings fresh understanding to reservoir permeability and a truer reflection of fluid flow behavior around producing wells. The traditional use of horizontal, vertical and directional permeabilities to reflect the conductivity of a formation to fluid flow is often misleading. Actually, the flow comes from everywhere in the reservoir and reduces to the wellbore, and in many cases ended at the perforations. The flow pattern takes a shape of a cone where the base is at the boundary and the head is at the wellbore or the perforation opening. This flow pattern produces a conical or "tapering" permeability. This new 3-D permeability term should enhance the accuracy of the models used to represent fluid flow in porous media.

A three-dimensional permeability term is newly introduced here. A three-dimensional spot gas permeameter device and techniques for measuring this term have been constructed in the laboratory. This device is intended to enable direct measurement of gas permeability at any spot on the surface of the sample, regardless of sample shape or size.

The issues of probe sealing and gas slippage have been resolved by introduction of a rubber baker at the tip of the probe, and by allowing low-pressure injection. A new mathematical model has been derived to describe the flow pattern associated with measuring gas permeability using the proposed device. The proposed mathematical model along with numerical solution presented is expected to find application beyond the gas permeameter case, as its usefulness is proven more relevant to reservoir behavior.
Field Study of Completion Fluids To Enhance Gas Production in the Barnett Shale
Authors: Penny G. S. , Pursley J. T. , Clawson T. D.
Published: December 2007

In this work field data and lab data are presented for various fluids pumped in the Barnett Shale. Recent fracture treatments have been light sand fracs in slick water consisting of water and friction reducer, with and without surfactants. Commonly used surfactants as well as a microemulsion system (ME) are evaluated.

Lab data is presented that illustrates how the microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture, hence longer effective frac lengths.

Over 200 wells have been treated and analyzed in the Barnett Shale for this study. Several side by side comparisons of treatment variations are possible. The addition of the microemulsion to fracturing treatments has resulted in more than 50% increases in load recoveries and 30-40% increases in gas production. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 in the Barnett shale with the inclusion of ME. This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.
Reinjection of Produced Water Mixed with Incompatible Aquifer Water into a Carbonate Reservoir—A Pilot Test
Authors: Raju K. U. , Nasr-El-Din H. A. , Al-Saiari H. A. , Abduljabar J. M.
Published: December 2007

Produced water re-injection (PWRI) has been carried out throughout the world to minimize the environmental impact of waste waters. There are a few studies on commingled produced water (PW) with injection water (sea or aquifer water), and still a lower number of reported field cases. This might be the first waterflood operation where incompatible waters with potential iron sulfide precipitation were injected into a tight carbonate reservoir.

Mixing disposal water containing high H2S and aquifer water containing dissolved iron results in the precipitation of iron sulfide particles. Coreflood studies with the mixed waters did not cause any adverse effects on the core permeability. This was attributed to the formation of wormholes created by H2S that is dissolved in the mixed waters. Based on extensive lab studies, a pilot test was conducted on Well B# 215, a water disposal well in Field B. The objective of this study is to confirm the feasibility of injecting mixed water into this well. The results, if successful, can be applied in fields with similar bottom hole conditions.

Injection of the commingled waters started a year ago. Extensive field samples (disposal, aquifer and mixed waters) were collected for geochemical analysis, sulfide and iron content before the onset of the pilot test. The percentage of disposal water in the commingled injected water was calculated based on the concentrations of various key ions (Na, Cl, Ca and Mg). These values were compared with flow rate of various streams measured in the field.

Based on the results obtained, there is no indication of formation damage noted in this well. The percentage of disposal water in the commingled water varied during the test period, but there was no damage noted. In addition, there was no need to flow this well back for cleaning, which resulted in significant cost savings and reduced environmental impact. This paper will discuss lab results and field application in detail. It will also address benefits gained from mixing aquifer water and disposal water.
Field Application of Emulsified Scale Inhibitor Treatment to Mitigate Calcium Carbonate Scale in Horizontal Wells
Authors: Nasr-El-Din H. A. , Al-Saiari H. A. , Al-Ruwaily A. -A. A. , Al-Gamber S. D.
Published: December 2007

Horizontal, extended-reach, and multi-lateral wells are drilled to maximize production from oil and gas reservoirs. Treating these wells with scale inhibitor is a real challenge. This is mainly due to reservoir heterogeneity and chemical placement.

Several horizontal wells were drilled in a sandstone oil reservoir. These wells were completed with 1,000 to 1,500 ft of pre-packed screens and produced wet crude with water-cut ranging from 5 to 30 vol%. The total dissolved solids of the produced water was nearly 8,000 mg/L. The bottom hole temperature is 152°F. The porosity varied from 5 to 30 vol%, whereas the permeability varied from 1 to 3,000 md.

Calcium carbonate scale was detected downhole due to temperature and pressure changes that occur at the intake of the electrical submersible pumps. The scale was removed by an acid treatment. However, there was a need to develop a chemical treatment to mitigate scale in these horizontal wells.

An emulsified scale inhibitor squeeze treatment was developed and applied in several horizontal wells in the sandstone reservoir. The emulsified inhibitor has high viscosity which decreases with the shear rate (shear thinning behavior). These rheological properties enhanced placement of the inhibitor across the target zone. Coiled tubing was also used to place the emulsified inhibitor, which also enhanced the placement of the inhibitor across the target zone. The treatments were successfully applied and no operational problems were encountered. Oil production and water-cut did not change as a result of the scale inhibitor (phosphonate-type) squeeze treatment. This paper will discuss the design of the emulsified scale inhibitor squeeze treatment, field application, and analysis of produced fluids.
Observations of Well Productivity and Skin in Sand-Control Completions Exposed to Precipitation of Sulfate Scales in the Near-Wellbore Area: A Case Study
Authors: Aksland T. G. , Andrews J. S.
Published: December 2007

This paper documents the performance of different sand control completion types in three subsea fields tied back to the Statfjord C platform. Seawater is injected as part of the reservoir drainage strategy on all three fields and this presents challenges related to precipitation of sulphate scales when the seawater mixes with incompatible formation water in the near wellbore area.

Well completions are of various types on these fields; conventional perforated casing with normal and orientated perforated phasing, sand screen, cased hole and openhole gravelpack. This basket of different completion solutions reflects the differing sanding tendencies of the various reservoirs and the general developments in completion technology throughout the field life. Sulphate scale buildup in the screen and near well bore has been found to be a major damage mechanism in all sand control completion types. The wells typically show immediate productivity index (PI) reduction following seawater breakthrough. Some data verify a stabilization of PI when the seawater cut reaches a high level. A comparison of the differing scaling tendencies of the completion types is made and guidelines on developments in skin as a function of production characteristics are presented.

Up to 1995 cased hole gravelpack was the dominating sand control technique in Statoil but poor trends in productivity following water breakthrough has lead Statoil to adopt openhole solutions. Theoretical arguments suggest that openhole completions are more tolerant of scale than cased hole gravelpacks. This paper documents whether any significant differences in scaling tolerance have been experienced in these fields. This has had consequences for estimation of productivity development and the expected scale prevention strategy chosen for the Statfjord depressurization project.

The paper shows that combined scale dissolver and scale inhibitor treatments have been successful in regaining productivity in these. Bullheading of scale treatments down the methanol service line has been a very cost effective method of treating scale depositions in wells tied back to the platform with distances of up to 7 km. For templates further from the platform, treatments are now performed from a dynamically positioned boat where a flexible hose is connected to the choke bridge.
Corrosion Mitigation With Gas-Hydrate Inhibitors
Authors: Hoppe R. , Martin R. L. , Pakulski M. K. , Schaffer T. D.
Published: December 2007

Gas production and transportation pose challenges for operators. Unprocessed gas streams in production and flow lines containing brine and hydrogen sulfide are particularly corrosive and susceptible to forming hydrates and scale deposits. Methanol is often added to such streams for hydrate prevention; however, methanol increases the corrosion tendencies of pipes and equipment because it can deactivate some Corrosion Inhibitors (CI) and adds oxygen to the system. As a result, if hydrates are controlled with methanol, the system requires extra amounts of properly selected corrosion inhibitors to counteract the oxygen induced accelerated corrosion.

Corrosion rates of tubular steel exposed to sweet and sour brines were investigated. The sweet conditions contained carbon dioxide saturated brine, methanol, corrosion and gas hydrate inhibitors. Hydrogen sulfide was added to the system to create a sour environment. Methanol and hydrogen sulfide present in wet gas streams create an environment difficult for corrosion control; they accelerate corrosion rates to the point of rendering some commercial corrosion inhibitors unsuitable for corrosion protection. It was discovered that some gas hydrate inhibitors offer both, hydrates and corrosion protection. In addition it was found that the corrosion inhibiting properties of these gas hydrate inhibitors were enhanced in the presence of hydrogen sulfide.

The dual action of the Low Dosage Hydrate Inhibitor (LDHI) described here can limit or even eliminate Corrosion Inhibitors in highly corrosive methanol containing sour gas/water streams; thus, LDHI application improves production and transportation economy by replacing high volumes of methanol with less costly volumes of LDHI and providing additional operational savings on CI.
4D Seismic Monitors Fluid Changes Over Time in a Carbonate Reservoir
Authors: Al-Jenaibi Mahfoud , Soroka William L. , Al-Jeelani Abu Baker , Hafez Hafez H. , Kleiss Erik , Melville Peter
Published: December 2007

Methods that can monitor fluid changes in a carbonate reservoir with time have the potential to help improve oil recovery from Middle East producing fields. Results from an onshore 4D seismic pilot study have successfully demonstrated that if performed properly, fluid changes in a reservoir can produce detectable differences in seismic data collected before and after the fluid change. The 4D seismic results, which show where a fluid change has occurred in the reservoir are produced by subtracting the two seismic images collected at different times. The 4D seismic method is found to be a good match with current production challenges that impact oil recovery, which include water flood override and inverse cone development. The 4D results are providing the reservoir engineer with flood-front information away from well control that can be used to quantify flood front efficiency and locate by-passed reserves.

The results from this 4D pilot successfully demonstrated that 4D responses can be observed in carbonate reservoirs where sufficient saturation changes have occurred. The 4D results showed that 3D seismic surveys can be repeated onshore with acceptable levels of background noise, if done in the correct manner. Model predictions from feasibility studies were found to be in agreement with the 4D results. 4D responses were found in the main reservoir layer in agreement with calibration wells. Detailed 4D validation showed the 4D results to be in agreement with available production logging tool (PLT) measurements. The 4D results also suggest that pressure changes may be contributing to some of the 4D responses.

Based on the results of this pilot, it has been shown that 4D can monitor saturation changes in a carbonate reservoir. The 4D results are helping evaluate sweep efficiency and identify potential bypassed oil reserves.
Downhole Scale Management in Gorm, Dan, and Halfdan, and Implications to Industry Trends
Authors: Jones T. , Koldig J. , Kogsbøll H. H.
Published: December 2007

Three oil producing fields in the Danish sector of the North Sea, Gorm, Dan and Halfdan, have been assessed for downhole scale control. All three fields have water injection. To date downhole scaling has not been perceived as a significant production problem in these fields. This paper presents the results of a review of the well service history for each well in the three fields which identified when and where scales had been encountered and estimated the impact of scale on well intervention operations. A thermodynamic equilibrium model for mineral solubilities was used to assess the scaling tendencies of sulphate and carbonate scales from bottom hole to wellhead. The observational data for downhole scale has been compared with the scaling predictions and a risk assessment for carbonate and sulphate scales developed for each well. The implications of this study on industry trends are discussed.
The Kinetics of Sulfate Deposition in Seeded and Unseeded Tests
Authors: Boak L. S. , Sorbie K. S.
Published: December 2007

In a previous paper1, we addressed the issue: what level of sulphate reduction is required to eliminate the need for scale inhibitor squeezing? In this earlier work, we developed the idea of a simple kinetic scheme for sulphate deposition based on a "safe envelope" concept within which the system could operate. Central to the "safe envelope" approach is the choice of rate constant for barite deposition and this can be estimated experimentally under various conditions appropriate to the specific field application. Experimental results on kinetic barite deposition in low sulphate brine mixtures were presented previously1. However, these previous results were carried out for unseeded solutions i.e. no solid barite or sand particles were added to the scaling solutions. The following questions were raised: if barite particles were present, would this mean that the solution supersaturation (Sp) would reduce to 1 very rapidly thus over-ruling any kinetic deposition effects?does the presence of sand particles have the same effect as barite particles?in the case of both barite or sand particles does the size of the particles (i.e. the surface area per unit mass) have any effect on the barite deposition rate?

In addition, a very simple kinetic model for bulk deposition of barite was used for which the long time behaviour was that barite is deposited until the limiting ion was totally consumed. However, it is known that barite has some solubility at higher levels of sodium chloride and the kinetic model should limit to this value. This may be an important consideration especially in lower sulphate (or lower barium) brines.

Experimental results are presented in this paper which both (a) address and answer the above questions, and (b) extend the analysis with an improved kinetic model for barite deposition. Even in the presence of seed materials (barite and sand of various surface areas), clear rate effects can be observed and rate constants can be derived. As expected, barite seed material of higher surface area induces faster depletion of the scaling ions to a supersaturation ratio of 1 than barite of lower surface area. However, allowing for the effect of surface area, the barite seed material shows a clearly enhanced potential to induce scale formation than the sand. In addition, the "safe envelope" model is extended by considering a more accurate analytical kinetic model which limits correctly to the equilibrium solubility of barite at long times.
Impact of In-Situ Sulfate Stripping on Scale Management in the Gyda Field
Authors: Mackay E. , Sorbie K. , Kavle V. , Sørhaug E. , Melvin K. , Sjursæther K. , Jordan M.
Published: December 2007

While barium stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium, strontium and barium ions, this paper presents evidence for in situ sulphate stripping in a sandstone reservoir. The formation brine composition suggests that a moderate to severe barite scaling tendency will require inhibitor concentrations in the range of 10-50 ppm to control scale, but in practice concentrations < 5 ppm are adequate. Investigation of the produced brine compositions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely from dilution of seawater with the formation brine. The question this paper addresses is what has caused this reduction in sulphate concentration.

The formation brine Mg/Ca ratio is < 0.1. Over geological time frames, the reservoir rock and formation brine will come into chemical equilibrium, the Mg/Ca and Na/Ca ratios in the brine being dependent on the respective ratios in the rock matrix. However, when seawater is injected, this equilibrium is disturbed. Since the Mg/Ca ratio for seawater is ~ 3, to reequilibrate an ion exchange mechanism causes magnesium to be retained from the brine phase onto the rock, and in return calcium is released from the rock into the brine phase. This is confirmed by lower than expected magnesium concentrations in the produced brine. The impact of the calcium release into seawater as it is displaced through the hot reservoir is to cause precipitation of calcium sulphate, this process resulting in the observed sulphate stripping.

This analysis is supported by the field data and by reactive transport calculations. Implications are drawn for scale management in this and similar fields with high formation water calcium concentrations.
Analysis of Organic Field Deposits: New Types of Calcium Naphthenate Scale or the Effect of Chemical Treatment?
Authors: Shepherd A. G. , Thomson G. B. , Westacott R. , Sorbie K. S. , Turner M. , Smith P. C.
Published: December 2007

Organic field deposits from distinct geographical regions were analysed using a wide range of analytical techniques, viz. for cation composition (EDAX), diffraction patterns (XRD), thermal profiling (DSC/TGA), naphthenic acid distribution using electrospray mass spectrometry (ESMS), nuclear magnetic resonance 1H NMR and solid state 13C NMR. Clear distinctions for end member soap types were observed with regard to the type and amount of cations, the naphthenic acid content, as well as their thermal behaviour. Specific soap samples were analysed along with their parent soap forming crude oils collected from the same field over a period of one year. The nature of two of these soap samples were found to be related to the particular chemical treatment on site. There were clearly observable differences in the final location within the surface facility, as well as the final composition (calcium content, acid distribution, presence of other chemical families) of these samples. These were suggested to be related also to crude oil chemistry changes and mitigation (chemical) strategies used. The implications of these new findings on the basic mechanisms of soap formation are discussed.
Analysis of the Mechanism of Transport and Retention of Nonaqueous Scale-Inhibitor Treatments in Cores Using Novel Tracer Techniques
Authors: Shields R. A. , Sorbie K. S. , Singleton M. A. , Guan H.
Published: December 2007

In recent years, a number of non-aqueous delivery systems for scale inhibitors (SI) have been developed which are designed to be applied as low damage, low watercut or pre-emptive squeeze treatments, e.g. in critical or expensive subsea wells. The mechanisms through which non-aqueous scale inhibitor systems operate is an important technical issue. Only when a good understanding of the transport and retention mechanisms is developed, can this be built into a model for designing such squeeze treatments (such as the SQUEEZE VI model). The experimental work in this paper focused on a specific "oil soluble" version of a standard penta phosphonate inhibitor (DETPMP), which has been described previously in the literature. Several floods have been carried out comparing corresponding non-aqueous and aqueous applications of DETPMP in order to better determine the main features of the transport and retention mechanism of the system. Novel core flood experiments with tracers in both the aqueous and oleic phases have been performed and are reported in this paper. Unique information is generated by designing very detailed flooding cycles and carrying out tracer floods at each stage. Results point to the formation of an immobile "emulsion like" third phase in this system. In order to confirm our proposed mechanism, non-aqueous inhibitor has also been applied at zero residual water saturation (100% oil) to investigate whether or not the tailing effect (or third layer deposition) could be generated without prior oil/water partitioning of the scale inhibitor. For this case, tailing of the brine tracer only was observed. Mass balance showed that there was still considerable retention of scale inhibitor that was ultimately produced during the aqueous post-flush.

The corresponding aqueous inhibitor coreflood showed similar returns to that of the previous non-aqueous experiment and no retardation of either the tracer species or the metal ions in the brine. No formation damage occurred for either phase after the inhibitor was injected. A further control flood (no SI treatment) proved that the brine tracer tailing arose as a direct result of the treatment.

The use of the tracer species in each (water and oil) phase is a genuine innovation, which provides a powerful additional technique for demonstrating the effect of chemical treatments on the flow and the retention of all fluids in the core.
Development of a Nonaqueous Scale-Inhibitor Squeeze Simulator
Authors: Vazquez O. , Mackay E. J. , Sorbie K. S.
Published: December 2007

This paper describes the development and application of a two-phase, multi-component, multi-layer, radial mathematical model capable of simulating aqueous and non-aqueous scale inhibitor squeeze treatments. The model considers the immiscible displacement of oil and water phases along with inhibitor transport in both phases and mass transfer between phases. It can model kinetic and equilibrium adsorption and desorption from either phase. The model has been validated by comparison with analytical solutions, standard conventional single-phase squeeze calculations and multi-phase reservoir simulation calculations.

Example results are presented, along with guidelines for appropriate use of these types of calculation in the design of aqueous and non-aqueous scale inhibitor treatments in wells across a wide range of water cuts.
Semianalytical Model for Reservoirs With Forchheimer's Non-Darcy Flow
Authors: Zeng F. , Zhao G.
Published: December 2007

This paper presents a semi-analytical model to investigate the effect of Forchheimer's non-Darcy flow on the transient pressure behavior of vertical well in an infinite homogeneous reservoir. This model uses the Forchheimer number, defined as the product of the reservoir non-Darcy flow coefficient and a reference rate, to quantify the non-Darcy flow in reservoirs accurately. The traditional non-Darcy skin factor, generally applied to model the non-Darcy flow in reservoirs, is employed to describe the non-Darcy flow across completions only. This study shows that the non-Darcy flow effect may influence the local flow rate profile over a reservoir region of several hundred times the wellbore radius. Therefore, it is not satisfactory to merely use the traditional non-Darcy skin factor to model non-Darcy flow in reservoirs.

Type curves are documented for both drawdown and buildup tests for the first time using the semi-analytical model proposed. It is observed that, when non-Darcy flow in reservoirs and/or across completions are considered, the dimensionless pressure derivative curves of drawdown tests have a wider-transition region with gentler slopes, while those of buildup tests exhibit a shorter transition region with steeper slopes. In the radial flow period, compared to the cases with only non-Darcy flow across completions, the cases with non-Darcy flow in reservoirs for drawdown and buildup tests possess dimensionless pressure derivatives that are moving downwards to approach 0.5 at decreasing rates more gradually and smoothly. In general, the pressure derivatives of drawdown tests are larger than those of buildup tests before they converge to 0.5.

With this model, the skin factor for non-Darcy flow across completions and the dimensionless Forchheimer number for non-Darcy flow in reservoirs can be estimated from a common drawdown or buildup test. Guidelines for interpreting field test data are presented. Several typical cases from the literature are analyzed, and better type curve matches and more reliable results are obtained.
Use of Wavelet Transform in PDG Data Treatment
Authors: Ribeiro P. M. , Pires A. P. , Oliveira E. A. P. , Ferroni J. G.
Published: December 2007

Since the beginning of the 80´s, more and more Pressure Downhole Gauges (PDG´s) were installed in production and injection wells. The main purpose was well monitoring and evaluation of reservoir performance. This kind of gauge provides a large amount of data, but there are different problems that do not allow their complete use. These problems are related to quantity and quality. Most of the softwares are not able to handle with all the data available in a long recording period, the main objective of the use of PDG´s. Besides that, gauges present noise and strange data (outliers). It becomes necessary to treat the data before its use in the study of reservoir behavior. The concept of wavelet transform was developed about a century ago, but it was during the 80´s that it received practical application. Now it is used in a wide variety of applications, and, especially in data treatment, it presents two main features that make it attractive: smoothing of the signal and retention of the details. In this paper we use the wavelet transform to overcome the main problems and enhance the reliability of the information contained in the data. We tested different wavelets with several decomposition levels against actual and synthetic data. The outliers must be removed before the wavelet analysis in order to enhance its performance. We show that there is no unique "correct" wavelet transform to apply in any flow period. For example, for some datasets the Daubechies 1 wavelet at decomposition level 6 was used for flow periods, and level 3 for build up. It is important to notice that the use of high decomposition levels may cause loss of information, as it is shown in some examples. The wavelet analysis was also used to recognize transients from its ability to enhance the details. This is particularly useful to identify flow rate changes when they have not been reported, for example. Finally, we propose a methodology to treat the data before its use in posterior interpretation.
Enhancing Formation Testing and Sampling Operations Through the Use of Log-Derived High-Resolution Mineral-Based Lithofacies Mapping
Authors: Elshahawi H. , Donaghy E. , Guillory C. , Kear G. R. , Kumar A. , Ardila M. , Williamson D. , Cantwell W. , Briscoe B.
Published: December 2007

Wireline formation testers are being routinely used today in a range of applications that spans pressure and mobility profiling; downhole fluid sampling and downhole fluid analysis; interval pressure transient testing; and micro-stress testing. These tools are able to collect large amount of data at multiple depths thus helping to quantify changes in rock and fluid properties along the wellbore, to define hydraulic flow units, and to understand the reservoir architecture.

A key input into the planning of wireline formation tester operations is an accurate understanding of the subsurface lithology, including subtle reservoir internal baffles and barriers. Not only is it necessary to understand where, in depth, the zones of interest exist, but also their compositions. Log-derived high-resolution mineral-based lithofacies can be used to improve the planning of downhole sampling operations and post-operational analysis. These are computed using borehole spectroscopy and high-resolution micro-resistivity image data. The spectroscopy data is used to classify the rocks into dry-weight mineralogy-based lithofacies based on a specifically designed ternary-diagram classification system. Calibrated high-resolution micro-resistivity image data is integrated with the generated dry-weight mineralogy-based lithofacies to compute a final mineral-based high-resolution set of lithofacies. All the computations can be accomplished on a workstation within a short time. The final lithofacies can be presented as a detailed geological column, or be input, as numerical data, for additional computation and modeling.

These lithofacies can be used to make sampling and pressure point selections. The speed of computation makes them useable for this purpose. The output can be quickly delivered to the decision makers whether in the office or at a remote location. The geological display of the lithofacies makes it readily usable and preferred for choosing sampling locations, whether for pressure or fluids. The inherent mineralogical content combined with the higher resolution bedding directly addresses the need to identify potential zones of interest otherwise indistinguishable. Critical depositional events such as maximum flooding surfaces, condensed sections, reservoir seals such as marl layers and shales, continuous or interbedded, are immediately identifiable with these lithofacies.

The use of log-derived high-resolution mineral-based lithofacies helps place the tool probes and/or packers at optimum formation and depth locations, thereby reducing risk and operating time, easing interpretation, and maximizing data and sample recovery.
Quantification of Carbon Dioxide Using Downhole Wireline Formation Tester Measurements
Authors: Müller N. , Elshahawi H. , Dong C. , Mullins O. C. , Flannery M. , Ardila M. , Weinheber P. , McDade E. Chinn
Published: December 2007

Carbon dioxide (CO2) occurrence in hydrocarbon bearing formations presents a challenge to the valuation and subsequent prospect development of the hydrocarbons. Corrosion is a major concern effecting capital and operational expenditures since the presence of CO2 can cause corrosion failures. Carbon dioxide also denotes an issue for health, safety and the environment (HSE) and is readily absorbed by elastomer seals, weakening the resistance of those seals and compromising the integrity of the fluid samples and the safety of equipment and personnel.

The conventional procedure to evaluate the CO2 content in a hydrocarbon bearing formation is to take fluid samples downhole or on surface during a well test and send the fluids to the laboratory for analysis. Both methods are compromised by the reactive nature of CO2, whose concentration can change significantly by reaction with formation waters, mud filtrates, etc. before reaching an analysis facility. Optimizing the fluid sample acquisition program to match existing fluid complexities is impossible without real-time analysis.

Recently, NIR (near-infrared) spectroscopy has enabled the real time analysis of the CO2 content in downhole fluid samples. This paper describes a new method for using DFA* (Downhole Fluid Analysis) in the real-time determination of the CO2 amount in the MDT* (Modular Dynamic Formation Tester) flow line. Extensive laboratory data from a research grade spectrometer and shop data with the downhole tool support the new methodology. Multiple interpretation algorithms have been developed for CO2 quantification and verified in the laboratory. Several log examples are given Mark of Schlumberger demonstrating successful CO2 detection and subsequent confirmation of the measured concentrations by the laboratory data.
Combining Continuous Fluid Typing, Wireline Formation Tester, and Geochemical Measurements for an Improved Understanding of Reservoir Architecture
Authors: Elshahawi H. , Venkataramanan L. , McKinney D. , Flannery M. , Mullins O. C. , Hashem M.
Published: December 2007

Identifying compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of identifying reservoir compartmentalization such as drillstem tests and extended well tests often become impractical in deep water settings with costs approaching the costs of new wells and emissions becoming increasingly undesirable. Thus, compartments often have to be identified by some other means.

Individually formation pressure measurements, downhole fluid analysis (DFA), and geochemistry are known to provide important information about reservoir architecture. When these powerful methods are systematically combined and applied to datasets, the synergy delivers a much more accurate and robust picture of the reservoir. In this paper, we review a number of case studies in which we have successfully combined continuous fluid facies mapping, pressure gradient measurements, DFA, and geochemistry for reservoir continuity assessment in a diverse range of geological settings including a wide range of field sizes, structural environments, reservoir lithologies, and oil types. Particular emphasis is placed on comparing the strengths and limitations of the different techniques in revealing reservoir architecture, especially vertical permeability barriers. We present a number of unambiguous cases, for which multiple data streams might be viewed as being somewhat redundant. More ambiguous cases, in which the multiple data streams are required to make a robust assessment of key reservoir properties, are also presented.
Expandable Sandface Completions—Design and Performance Review of Single-Zone Applications and Journey to Next-Generation Multizone Systems
Authors: Morgan Quentin , Jones Colin , Macarthur Ally
Published: December 2007

The advent of Expandable Sand Screens (ESS) technology heralded a new era in mechanical downhole sand control by specifically addressing perceived limitations of standalone screens (SAS) and complexities of gravel packs. To date, ESS has been installed in over 400 wells worldwide under a variety of operating conditions, with the majority in single-zone environments.

This paper describes designs aspects and applications engineering behind historical ESS applications, and discloses findings from a recent survey of these installations to derive key performance and reliability indices. A discussion of how these findings have been used to better understand and refine operations envelope for ESS and improve robustness of applications engineering to yield greater system reliability is also included.

The productivity benefits of ESS technology, has been the subject of several authorative papers, with growing body of anecdotal evidence now in the public domain quantifying productivity gains achieved compared with other wells employing variety of other sand control techniques, particularly in open-hole environments.

The drive for maximum well productivity compels many operators to consider openhole completion strategies. However, this has often not been possible through inability to achieve effective zonal isolation. Though ESS has been interfaced successfully with available annular barrier technologies to satisfy this goal in cased hole, technical limitations have constrained use in open hole.

This paper documents therefore an 18-month expandable technology research and development effort that has culminated in the introduction of a wholly new multi-zone Expandable Reservoir Completion (ERC) architecture, where selective isolation or production provides advantage.

This next generation ERC system combines slotted and solid expandable technology to deliver a reservoir completion with a combination of openhole production performance and casedhole functionality. Early results from initial ERC installations are showcased to illustrate system potential.
High-Impact-Resistant Cement Allows Challenging Sidetrack in Abu Dhabi
Authors: El Hassan Hassan , Shagnoubi Mahmoud , Belmahi Abdel , Jarouj Haitham , Voon Eric
Published: December 2007

The process of sidetracking an existing borehole with a balance cement plug has historically been time consuming and problematic for the drilling industry. The formations in the Middle East are classified as some of the most competent formations in the industry. These formations present its own challenges when attempting to sidetrack because of changes in the drilling trajectory. Historically, the operator has faced problems sidetracking in the Shilaif formations, where longer drilling time and/or numerous cement plugs are required to achieve this objective. These requirements lead to an increased in drilling costs.

Traditionally, a conventional cement system with a high compressive strength is used for sidetracking purposes. However, these cement systems have low resistance to impact and shock and hence will fail through rupture when placed across the competent formations. An optimized particle sized distribution cement system, combined with engineered metallic micro ribbon technology has allowed the sidetracking to be achieved efficiently.

The technology improves the durability and the resistance of the cement to load bearing capacity and fracture propagation. Further laboratary testing comparisons have confirmed the enhanced mechanical properties of this cement system. As a rule of thumb, the industry relied on the rate of penetration (ROP) as an indicator of how good a cement plug is for sidetracking purposes. It is believed that the lower the ROP is, the easier the sidetrack can be achieved.

As the technology is "tougher" than the formations, the drilling bottom hole assembly (BHA) can be deflected/ sidetracked efficiently and drilling operations resumed, in a shorter period of time compared to using conventional cement systems.
An Innovative Inert Material To Cure the Losses in the Brent Depleted Reservoirs— North Sea Case Histories
Authors: Shuttleworth Nigel , Frederiks Kees , DerPlas Klaas Van , McCraith Steve , Taoutaou Salim
Published: December 2007

Drilling in the Brent field began to experience severe lost circulation problems after the start of depressurisation in 1998. The losses occurred in the reservoir sections, which were penetrated by extended reach and near-horizontal wells. In contrast, wells drilled before the onset of depressurisation experienced few losses.

The lost circulation problems resulted from a narrowing of the drilling operating window as reservoir depletion gradually reduced the fracture gradient. Numerous interbedded reservoir shales, which were subseismic in thickness, required a minimum mud weight to maintain stability, especially in the subhorizontal sections. Problems became acute when the fracture gradient was reduced to a level below the equivalent circulating density (ECD) required to successfully drill the shales.

The rate of decline in the fracture gradient was much lower than would have been predicted from conventional geomechanics estimation, and this extended the duration of the Brent drilling programme during depressurisation. Drilling and cementing the Brent reservoir with no losses has proven very difficult in the past 2 years.

This paper will describe the lost circulation problems when drilling and cementing the Brent reservoir and the new approach used during cementing to cure losses without adding constraints to the offshore operation.
A New Neural Network Approach to Reservoir Permeability Estimation from Well Logs
Authors: Lim Jong-Se , Park Hui-June , Kim Jungwhan
Published: December 2007

Reservoir permeability is one of the most important properties of oil and gas fields for reservoir characterization. In un-cored intervals or wells, reservoir description and evaluation methods using well log data represent a significant technical as well as economic advantage because well logs can provide a continuous record over the entire well where coring is impossible. Permeability determination from well logs in heterogeneous formation has a difficult and complex problem to solve by conventional statistical methods. Recently artificial neural networks (ANNs) have been successfully used to solve many of complex problems in reservoir permeability estimation. However, the applications of the neural network to mapping complex nonlinear relationship have revealed a number of unsolved technical limitations despite of the high versatility. This paper proposes a group method of data handling (GMDH) based on polynomial neural network (PNN) for permeability prediction from well logs to alleviate limitations of the conventional neural network approach. The PNN evolutionally synthesizes network size, connectivity, processing element types, and coefficients for globally optimized structure through training. This self-organizing approach automatically presents internal relationships among data in the polynomial forms, and enhances data approximation and explanation capabilities of resulting data-based learning models. This technique is demonstrated with an application to the well data in offshore Korea. The comparative study with conventional neural networks reveals that the proposed model gives a relatively positive performance although the prediction accuracy of the PNN model is affected by errors in measurement data. The PNN is a practical and powerful tool for predicting reservoir permeability of a heterogeneous formation utilizing well logs.
Application of Intelligent-Completion Technology in a Triple-Zone Gravel Packed Commingled Producer
Authors: Brock W. R. , Oleh E. O. , Linscott J. P. , Agara S.
Published: December 2007

Many oil fields are comprised of stacked reservoirs, each requiring multiple individual wells for their proper and timely depletion. By commingling multiple reservoirs in a single well, the total number of wells required for full field development can be significantly reduced and the depletion life can be better managed within the design life of the attendant facilities. This can result in a significant cost savings over conventional development especially in the offshore environs.

Historically one limitation of commingling has been the inability to fully optimize the recovery of the reserves from each interval. In many areas, commingling is restricted or prohibited by regulation because of this inability to optimize the depletion of the reserves. Use of intelligent completion techniques can provide the capability to properly manage the recovery of reserves from each individual zone in a commingled completion.

As a follow-up to a recent discovery, Mobil Producing Nigeria Unlimited (MPN) drilled a long-reach producing well in the Usari field from an existing platform which was completed as a commingled producer in three of the seven discovered zones. Each of the three zones was completed with a gravel pack, a hydraulically operated multi-position flow control valves and downhole gauges which provide full control of each zone. This approach allows for the assessment of the characteristics of each reservoir and proper assessment of the uncertainties associated with a full development of the discovery prior to committing to new wellhead platforms. In addition, the average first-year rate for the well was approximately 11,000 BOPD whereas a single producer would have only provided about 7,000 BOPD.

This paper will focus on the concept selection, interaction with regulatory agencies, the installation and the performance results-to-date. The discussion will also address the reservoir surveillance and management of the three commingled reservoirs including production back-allocation and optimization.

This application is the first recorded use of hydraulically operated multi-position flow control valves (FCV) in a 9-5/8″ triple-gravel packed completion. The learnings from this well are in the area of well planning, equipment installation and reservoir management.