bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Summary
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

Abstract
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

Abstract
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

Abstract
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 &lt; 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 &lt; 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

Abstract
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.