bluuebunny/crossref_metadata_2025 huggingface dataset:
FAWAG: A Breakthrough for EOR in the North Sea
Authors: Aarra M. G. , Skauge A. , Martinsen H. A.
Published: December 2007

The application of FAWAG (Foam Assisted WAG) on the Western fault block at the Snorre field has qualified foam as a gas mobility agent for North Sea reservoirs. Results from the foam mobility control trial on WFB at Snorre, well pair P32-P39, were conclusive. The results show that gas breakthrough was delayed and the Gas-Oil-Ratio (GOR) was considerable lowered compared to pre-foam gas injection cycles. Large volumes of gas have been stored in the reservoir. Analysis has shown that gas material balance, decline analysis, and simulations all give consistent results. The expenses for FAWAG on Western Fault block (WFB) was 1M USD, and additional oil recovery value is estimated to ~ 25-40M USD at current oil prices.

The FAWAG on WFB has been history matched using a commercial foam simulator. Assuming the same foam properties as in the history match, simulations have been performed to evaluate further potential for FAWAG on WFB of the Snorre field and on the Visund field. These predictions show a significant potential for increased oil production and storage of gas: –Simulations of a 2nd FAWAG injection in the same well pair, P32-P39, estimate an increased gas storage at the same level as for the 1st FAWAG injection, and indicate a maximum increased oil recovery potential in the range of ~ 400 000 Sm3.–The potential for FAWAG in a neighboring well pair in WFB indicate an increased gas storage of ~ 106 MSm3 and a maximum increased oil recovery potential up to ~ 650 000 Sm3.–The potential for FAWAG injection in the N1 segment of the Visund field suggest an increased gas storage potential of 191 MSm3 and an increased oil recovery potential of 217 000 Sm3, when injecting 400 tons of 38% active surfactant.
Artificial Neural Network Architectures for Predicting Two-Phase and Three-Phase Relative Permeability Characteristics
Authors: Silpngarmlers N. , Ertekin T.
Published: December 2007

Laboratory determination of relative permeability characteristics is labor intensive and can be complicated. Empirical models to predict relative permeabilities based on rock and fluid properties have experienced relatively limited success. Hence, alternate methodologies for accurate determination of relative permeability characteristics are always desirable.

In this study, two-phase and three-phase relative permeability predictors are developed using backpropagation networks. In this category of networks, information is passed from input layer to output layer, and calculated errors are propagated back to adjust the connection weights in a sequential manner to improve the predictive capabilities of the models. In the development of the models, experimental relative permeability data along with some commonly reported rock and fluid properties obtained from the literature are used during the training stage, while some other data sets are preserved to test the prediction ability of the models. The two-phase relative permeability models are found to perform in a satisfactory manner within a wide spectrum of basic rock and fluid properties. Similarly, three-phase relative permeability models are observed to have good predictive capability in accurately producing the missing entries of three-phase data sets for a series of isoperms, and in constructing the missing isoperms for a system under consideration. Furthermore, they are found to be capable of effectively predicting the three-phase relative permeability values at various saturation combinations for systems with different rock and fluid properties.
Riserless Subsea Completion with Disappearing Plug Technology
Authors: Stair Craig D. , Stuckey Joe T.
Published: December 2007

The installation of a subsea tree from a floating drilling rig is one of the most complex and time-consuming portions of a deepwater subsea well completion. Removing subsea tree installation from the rig "critical path" would yield a step-change reduction in the time and cost to complete a subsea well.

Disappearing plug technology holds the key to achieving this improvement. Regulations (and good practice) dictate the use of a plug set in the tubing hanger of a completed well to provide a barrier to well flow. Until recently, most subsea trees were installed from the drilling rig on a completion riser, after the BOP stack and marine riser were removed. The completion riser also provided the conduit to remove the tubing hanger plug. "Disappearing plug" technology eliminates the need for the completion riser and drilling rig during subsea tree installation because it acts as a well barrier, performing the same function as the tubing hanger plug, until it is opened remotely from the host facility.

This paper discusses the application of disappearing plug technology to a subsea project, the synergies created between downhole completion operations and subsea installation activities, and the resultant time and cost savings.
On the Relationship between Resistivity and Permeability Anisotropy
Authors: Georgi D. , Bespalov A. , Tabarovsky L. , Schoen J.
Published: December 2007

Measurement of resistivity anisotropy is critical to reserve estimation and permeability anisotropy determination is key to efficient hydrocarbon exploitation. It is now possible to measure resistivity anisotropy with new wireline, multi-component induction hardware. However, it is difficult to directly measure or determine permeability anisotropy. Thus, it would be beneficial to be able to relate resistivity and permeability anisotropy and predict kv:kh from Rh:Rv (where kv and kh are the vertical and horizontal permeabilities, and Rv and Rh are the vertical and horizontal components of formation resistivity).

We know that both resistivity and permeability anisotropy are scale dependent. In our study, we define three scales for formation anisotropy properties: The Micro-scale relates directly to the properties of individual components (e.g., sand and shale). The Macro-scale is an intermediate scale defined by the vertical resolution of the measurement tools. Most logging tools are not capable of resolving the individual lamina in laminated sand-shale sequences. In this case, the "macroscopic anisotropy" can be described by the well-known rules for conductors connected in parallel and/or in series. At the Reservoir-scale, anisotropy is governed by interconnected channels formed by gaps in the relatively impermeable shale layers.

We have developed a numerical simulator that allows us to model at all scales the anisotropy for resistivity and permeability for arbitrary three-dimensional, periodic structures. The simulation results have been verified with known analytical solutions. With this model we have explored reservoir-scale anisotropy as a function of the lateral extent of the shales and sands. By varying the thickness of the sands and shales, we investigated the effect of net-to-gross on the electrical and permeability anisotropy.

From our studies we conclude that the relationship between resistivity and permeability anisotropy is not trivial. On the smaller scales it is controlled by the spatial distribution of the pore-space properties and on the larger reservoir scales by the spatial distribution of the sand bodies and gaps in the shale barriers.

We show both numerically and theoretically for 2D structures that resistivity and permeability anisotropy are identical for cells with inverse property contrasts. This implies that fluid and current flow anisotropy are equal. However, this does not hold for every 3D geometry and in general there is no correlation between permeability and resistivity anisotropy on the macroscopic or reservoir scale for laminated sand-shale systems.
Optimization of Microbial Flooding in Carbonate Reservoirs
Authors: Almehaideb Reyadh , Zekri Abdulrazag Y.
Published: December 2007

Up to date, several investigators have studied the possibility of using microorganism in improving oil recovery, but little work has been reported regarding optimization of the process. In the laboratory, bacteria have been shown to produce chemicals such as surfactant, acids, solvents, polymers, and gases (mainly CO2) that can significantly contribute to improving displacement and sweep efficiency. Some of these microorganisms can withstand the harsh environment of the oil field and grow at a substantial rate feeding on the organic matter and crude oil itself, thus leading to improvement of oil recovery. Moreover, the MEOR process is friendly to the environment. Several field trials have been reported that showed the potential of bacterial enhanced oil recovery (BEOR) in improving oil recovery.

Because these microorganisms are living organism and their behavior is difficult to predict, therefore no attempt has been made to study the parameters that control the process performance. This has become the main objective of this work. In this work, we investigate the field parameters that affect the design a new process of Microbial Enhanced Oil Recovery in order to achieve optimum oil recovery. In order to reach this goal, the reservoir engineering factors that affect the recovery efficiency are defined first. These field parameters considered the most relevant and chosen for this study are the injected bacteria concentration, the adaptation time, the optimum slug size of bacteria solution, and the process application time. The capability of the microbes to transmit through a heterogeneous system and in long cores, and the effect of bacteria on rock wettability are also investigated.
Application of a New Crosslinked Polymer Displacement Technology at Bo-19 Block in Gudao Oilfield
Authors: Song Wanchao , Zeng Xianxiang , Yao Haixia , Li Jiyong , Lv Xihui , Tian Yuqin , Guo Yanjun
Published: December 2007

A new EOR method of Crosslinked polymer displacement technology is introduced in this paper. The crosslinked system is based on the reaction of Cr(III) in crosslinker with hydrolysed polyacrylamide(HPAM). After gelation, the system has some character such as good viscoelasticity, good thermal stability, and high salinity resistance. The viscoelasticity of crosslinked system can reach 2–3 times simple polymer solution. As a new system combining profile modification and flooding, it can be applied in high water-cut and severe heterogeneous reservoirs. Because of delayed crosslinking property, it can not only improve profile during injection, but also flow increase volumetric sweep efficiency. Having been injected into reservoir, crosslinking polymer can block and adjust high permeability zones in deep section, and improve sweep volume, and decrease water to oil mobility ration, thereby enhance recovery efficiency.

The pilot is is in BO-19 block in GUDAO oilfield, which is characteristic of positive rhythm deposit, loosed sand cement, high density and high viscosity etc. The reservoir temperature is 73°C, the viscosity of crude oil is 80mPa.s, density is 0.9030g/cm3 at reservoir conditions, permeability is 1000–2000×10−3μm2 and the formation water salinity is 6453mg/L. It has 21 injection wells and 40 production wells, the oil-bearing area is about 2.4km2 and reserve in place is about 737.3×104 tons. From 1999 to 2001, 0.15PV (pore volumes) of crosslinked polymer solution has been injected, and a good effect of increasing oil and decreasing water appears, oil production increases from 201 to 350 tons per

day, composite water cut decreases from 91.3% to 84.6%, cumulative incremental oil reached 5.0×104tons.
Restudy of Main Factors of Effects on ASP Flood and Expansion of Capillary Theory in Heterogeneous Reservoirs
Authors: Hou Jirui , Liu Zhongchun , Yue Xiang'an , Zhang Shufen , Yang Jinzong
Published: December 2007

The demonstration projects of ASP flooding have been implemented in Daqing oil field. With the enlarging of the scope of testing areas, the effects of the scale production resulted from high concentration of alkali (1.2%wt) have been gradually exposed. It resulted in many questions, such as the increase of the resistance of formation's percolation, the decrease of production and the blocking of pumps. All these have become the severe obstructer of the application of ASP flooding.

As to the formation conditions in Daqing oil field, the effects of alkali concentrations on the curling degree of polymer molecules in ASP solution have been studied by using Nanoscope IIIa type AFM in Digital Instruments Company in America. The results show that the chains of polymer molecules spread in liquid phase without alkali, but the chains curl for adding alkali. In the condition of high concentration alkali, the curled chains of polymer molecules are very tight. The polymer molecules do not spread fully, and exist in the state of assembling of many molecules on their sides. Correspondingly, the rheological characteristic of ASP solutions has been studied by using HAAKA apparatus for analyzing rheology. Moreover, the physical simulations of ASP flooding on three-dimensional heterogeneous models and filling sand tubes have been performed. The results show that the ASP solution with a low alkali's concentration and a higher viscoelasticity can get a very high oil recovery by enlarging sweep efficiency and unit displacement efficiency. To heterogeneous reservoir, the viscoelasticity of ASP solution plays a more important role than the ultra low interfacial tension. Else, since the effective distance of action of the surfactant over 60% of ASP cost is very limited in formations, the ultra low interfacial tension is difficult to bring a benefit which it should does. Through a lot of calculations, the revised correlation of capillary number has also been presented in this paper. Finally, through analyzing of the effect of the demonstration project in west of Xing-2 area, the significance of the viscoelasticity has been verified again from the field tests. The feasibility of ASP flooding with low alkali has been determined further, and a new method has been studied for solving alkali scale in ASP flooding in this paper.
Overview of Stimulation Technology for Horizontal Completions without Cemented Casing in the Lateral
Authors: McDaniel B. W. , East Loyd , Hazzard Vance
Published: December 2007

Many horizontal wells have been drilled in low- to moderate-permeability formations and completed in a manner that assumed there would not be a need for a true "stimulation" treatment. This has been a widespread occurrence in both the U.S.A. and Canada, and to a lesser extent for other locations around the globe.

Completing the horizontal section either openhole or with a noncemented liner is economically attractive. However, in many low-permeability reservoirs, and some with moderate-permeability values, production has often been below expectations and sometimes commercially unfeasible, even following efforts to overcome near-wellbore damage problems. This is especially true when considering only completions in reservoirs other than fractured chalks. In more permeable reservoirs, the higher investment costs of underbalanced drilling have often allowed low-damage completions with good economic return. In lower permeability reservoirs, this approach has not often been successful.

Previous studies offer numerous success stories for stimulating cased/cemented horizontal completions in low-permeability reservoirs.1-8 To achieve proper stimulation with a technique such as fracture-acidizing or hydraulic fracturing with proppants, operators must incorporate an economical, effective method for controlling fluid or proppant placement. However, operators faced with limited producing potential need to reduce well costs, so they often consider openhole or simple liner completions a necessity. Unfortunately, few proven technologies exist for controlling fracture placement in noncemented wellbores. In some cases, high risk or very high cost is associated with these technologies, depending on reservoir conditions or the potential for production improvement.

In attempting to solve these problems, operators have used several approaches. Some have succeeded both mechanically and economically; some have only been mechanical successes, while others have fallen short on both considerations. To achieve significant long-term production improvement, conventional proppant-laden fracturing treatments, waterfracs (those using very little proppant), and fracture-acidizing of carbonate formations all need some type of control over fracture placement along the horizontal. This paper examines several approaches used in attempting to solve these problems and analyzes the reasons why each succeeded or failed mechanically and/or economically.
Effects of Reservoir and Operational Parameters on the Succession-of-Pseudosteady-States Modeling of a Closed Gas Reservoir
Authors: Lee K. S.
Published: December 2007

The succession-of-pseudosteady-states approach, originally established for linear diffusion problems, has been extended to calculate the long-time behavior of real gas flow in a closed reservoir. The applicability and limitations of the approach were examined through a series of numerical simulation works and error analysis. It is intent of this paper to provide a quantitative guideline on the use of pseudosteady-state approach to real gas flow problems.

To extend the pseudosteady-state approach, a linearized form of gas diffusivity equation was derived by introducing normalized pseudovariables to the equation. Extensive numerical simulation study has then been performed to quantify effects of various reservoir and operational parameters which may develop nonlinearities in the gas flow problems. The parameters considered are permeability, pressure, flowrate, and gas properties. Results of simulation studies have been examined with cumulative error analysis. For most cases, a fairly good agreement was observed between the predictions from the pseudosteady-states model and conventional reservoir simulation. Error analysis demonstrates that the permeability and reservoir pressure can affect the results of a succession-of-pseudosteady-states approach. The accuracy depends weakly on the flowrate, and is almost independent of specific gravity. Except for the cases of very low permeabilities, however, computations indicate that neglecting infinite-acting flow behavior does not introduce serious error in the procedure. The validity and computational efficiency of the succession-of pseudosteady-states approach for the analysis of gas reservoirs has been confirmed in the present work.
A Nested Neuro-Fractal-Stochastic Technique for Modeling Naturally Fractured Reservoirs
Authors: Tran Nam H. , Rahman M. K. , Rahman Sheik S.
Published: December 2007

Naturally fractured reservoirs (NFR) have recently attracted intensive research attention, because the world market is increasingly under pressure to exploit energy from unconventional sources such as naturally fractured oil, gas and hot dry rock reservoirs. Modeling of naturally fractured reservoirs has so far been considered complex and progress is still inadequate. This paper presents a new integrated methodology to model natural fracture networks. The methodology integrates the features of geological, statistical and artificial intelligence techniques in a nested loop to characterize fracture networks observed in the field, and then to simulate it.

Natural fracture parameters such as size, orientation and aperture are of different scales and relevancies. Their characterization is also, to some extent, technique dependent. Some secondary parameters such as fracture density and fractal dimension are therefore defined for better description of these reservoirs. The relationship between the primary and secondary fracture parameters is complex and has not yet been fully understood. A neural network tool has been incorporated in the proposed methodology to establish this relationship by processing field data available from logs and core analysis, and to define the relative importance of primary parameters in this relationship. Combining the primary and secondary parameters at well locations, natural fracture networks are simulated stochastically in the whole reservoirs. The nested technique is used to model different degrees of heterogeneity in the reservoir: at the reservoir scale, locations and properties of major faults and joints are taken into account; and at the well-bore scale, a fracture network is mapped with its characterized fracture parameters. The simulated reservoir is thus expected to map more closely with the physical distribution of fractures and their properties than that are achieved so far with simplified stochastic-fractal approaches.
In-Situ Contamination Monitoring and GOR Measurement of Formation Fluid Samples
Authors: Dong C. , Mullins O. C. , Hegeman P. S. , Teague R. , Kurkjian A. , Elshahawi H.
Published: December 2007

Formation fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. Particularly in subsea wells, flow assurance is a major concern, and formation fluid samples from openhole logging help operators optimize investment in both upstream and downstream facilities.

Oils have different color due to the amount of large, complex aromatic compounds they contain. Since synthetic and oil-base drilling muds contain simple aliphatic compounds, they absorb little in the shorter wavelength color channels. The Oil-Base Contamination Monitoring (OCM) technique uses optical means to monitor the buildup of color during sampling. The technique provides real-time analysis of sample contamination, as well as prediction of how long it will take to achieve an acceptably low level of contamination.

As reservoir fluid replaces filtrate in the flow line, the optical density (OD) of the methane signal also increases, in proportion to the oil's methane content. Methane detection is essential for condensates and for lightly colored crude oils. For such fluids, the color buildup becomes difficult to detect; however, the high methane content of these fluids makes possible a reliable methane-based OCM algorithm. Furthermore, the methane content can be used to determine the gas/oil ratio (GOR) of the sample. When these methane-based techniques are applied for darker oils, the color absorption of the crude extends to the near infrared region and covers the methane molecular vibration peak, resulting in a higher methane signal optical magnitude. If uncorrected for, this would result in errors in the methane-based contamination prediction and GOR determination.

In this paper, we show how to measure GOR downhole during sampling using the OD of the methane signal. We also describe a decolorization algorithm to remove the color effect from the methane optical channel. The algorithm is based on the exponential decay of color absorption toward the high wavelengths in the near infrared region. After decolorization, the methane channel contains only methane molecular vibration absorption, which is then used to derive an accurate crude oil contamination value and GOR.
Unconventional Multiple Fracture Treatments Using Dynamic Diversion and Downhole Mixing
Authors: Surjaatmadja Jim B. , McDaniel B. W. , Sutherland Rod L.
Published: December 2007

This paper reviews a unique, relatively new stimulation process that uses dynamic fluid energy (instead of mechanical methods) to isolate treatment fluid flow to a specific fracture point along the wellbore. A process of hydrajet-fracturing has been developed by merging four existing technologies: hydrajetting, hydraulic fracturing, jet pump technology, and dual-path fluid injection. These have been meshed to create a method whereby a wellbore is perforated (if necessary) and a fracture is initiated and placed accurately at a specific location, and then soon repeated at another chosen location uphole, or closer to the heel when in a lateral wellbore. The process was later expanded as a hydrojet-squeeze stimulation method also, even to the point of applying both of these applications while stimulating a single wellbore.

This process employs two independent fluid streams: one in the treating string and another in the annulus. As these fluid paths will be supplied with separate pumping equipment, we have the option to instantaneously alter the downhole mixture that is being used to treat the formation at the current location of the jetting tool. An additional use of this two-stream feature is the capability to pump two different fluids that can be mixed downhole with a tremendously high energy to form a homogenous mixture at the fracture entry point, even creating foamed fluids insitu for some applications.

This technique has been used to stimulate more than 50 horizontal or highly deviated wells (and a few vertical wells) as of the preparation of this paper, both proppant-laden fractures and fracture acidizing treatments. On average, more than 7 fractures were placed along a typical horizontal wellbore, typically several hundred feet apart without the use of mechanical sealing equipment. Additionally, numerous horizontal wells with higher permeabilities have been stimulated using the hydrajet-squeeze process alone.

The diversion process follows a dynamic isolation approach that uses a high-velocity, high-energy jetted fluid. The process was originally developed for its unique stimulation capabilities in openhole horizontal wells, but has been extended to wells that have cemented or non-cemented liners, whether vertical, deviated, or horizontal and even to multilateral completions (or recompletions).

This paper offers insight into many of these treatments, including the different well situations, design considerations, operations, and available results of the treatments. Possible unconventional approaches using this concept and a unique implementation in the field are also discussed.
Fiscal Regimes Competitiveness Comparison of Oil and Gas Producing Countries in the Asia Pacific Region: Australia, China, India, Indonesia and Malaysia
Authors: Dharmadji Temmy , Parlindungan Tumbur
Published: December 2007

Fiscal Regimes is one of the most important factors to be considered for investment decisions in oil and gas industry. Royalty Rate, Cost Recovery, Contractor Share, Domestic Market Obligation, Investment Credit, Signature Bonus, Production Bonus, First Trance Petroleum and Corporate Tax Rate have a significant effect on the investment decisions.

The paper examines and compares the fiscal regimes in Australia, China, India, Indonesia and Malaysia. In order to analyze the advantages and disadvantages of each fiscal regime, the economic analysis of the same hypothetical fields with the applications of those different fiscal regimes are presented and discussed. Generic fiscal terms are used in the analysis since contractors usually can negotiate the special terms with governments.

The information of this paper is useful for oil and gas companies around the world when they want to decide where in Asia Pacific Region they want to invest their money. They can compare which fiscal regime gives them the most favorable return of their investment. In addition, the information is useful for the governments when they want to assess their fiscal regime competitiveness compared to other fiscal regime in that region. In depth analysis on fiscal regimes of those countries is very important for oil and gas industry and it will add to the knowledge base of this industry.

Conclusions are made of the effects of these different fiscal regimes on oil and gas company cash flow and profitability and how they affect company investment decisions in oil and gas industry and government policy.
Relative Permeability Measurements of Composite Cores, an Experimental Approach
Authors: Zekri Abdulrazag Y. , Almehaideb Reyadh A.
Published: December 2007

Some experimental tests require floods to be carried out on longer cores, typically 1–3 feet long. When whole cores are not available, side-wall cores each measuring 3–6 inches long are put together to make a composite core. It is the prevailing practice in the industry for composite core floods to order cores in an ascending permeability order, as this is thought to lower capillary forces for high flow rates and thus lessen the capillary end-effect. Huppler (1969), through a numerical study and neglecting capillary end-effects, proposed the criteria that cores should be ordered in such a way that the harmonic average between sections should be as close as possible to the overall average of the composite. Also, the core with permeability closest to the average is placed at the outlet position. Recently, with certain assumptions, Langaas et al. (1998) have demonstrated through a theoretical study that a new criteria should be followed, i.e. ordering cores in a descending order. They showed that this would produce residual oil saturation closest to the value for the composite, if it were considered as a single core with average properties. In this work, we present results of an experimental composite core flooding study that was designed to test how the properties of the individual cores in a composite core-stack influence the measured residual oil saturation and relative permeabilities for an oil-water system typical of a water flood. The study was conducted for carbonate cores, predominant in the lower Arabian Gulf region, and involved composite cores stacked in an ascending, descending, and random order (according to the Huppler criteria). Results of the experimental runs in this study show a significant effect of ordering on relative permeability evaluation, with values for Krw and Kro for composite cores in a descending order significantly different from the values for both random ordering and ascending ordering. Also, the recovery factor was highest for the composite core ordered in a descending order, followed by ordering according to Huppler's criteria, and then ascending order. These findings support Langaas et al. findings, i. e. the best ordering criteria is after decreasing permeability along the flow direction such that the core with the highest permeability is placed at the inlet.
Sample Quality Prediction with Integrated Oil and Water-based Mud Invasion Modeling.
Authors: Proett Mark A. , Chin Wilson , Wu Jianghui , Manohar Mohan , Belanger Dave
Published: December 2007

Wireline formation sample contamination and quality control depend on formation parameters and mud characteristics. The invasion process is a complex multi-phase problem particularly when mixed miscible and immiscible fluids are present. The scenario is complex when either oil-based mud (OBM) or water-based mud (WBM) invades a reservoir with initial oil-water concentration. Either oil or water may be the principal contaminating fluid depending on mud type. This paper presents the results of analyses based on the first wellbore invasion simulator that models the complete problem. The governing differential equations for miscible and immiscible fluids, with fluid compressibility, rock heterogeneity and anisotropy, and gravity are developed from first principles and implemented in a finite difference code. In addition, general boundary conditions allow dynamically coupled mudcake growth, which do not assume that mudcake completely controls invasion into the formation. The simulator developed also allows bed boundary modeling as well as assessment of multi-probed pumping.

Previous invasion simulations in the literature are based on two-phase immiscible fluids where WBM invades an oil zone. Of greatest interest, however, in sampling quality is the OBM invasion problem. OBM contains a mixture of oil and water, where the oil is the continuous phase and encapsulates the water. The continuous mud filtrate phase dominates the invasion and, according to molecular diffusion dynamics, mixes miscibly with formation fluids. The effects of anisotropy, mudcake growth, gravity, and two-phase flow properties on this problem can thus be assessed.

While invasion has a strong influence on potential sample quality, the pumpout wireline formation tester (PWFT) sampling procedures can be designed to have an equal influence on sample quality. The new simulator can evaluate the concentration of the fluid phases and types during the sampling process.

Although it is a fact that sampling rate as well as the placement of a probe within a zone can have an impact on sample quality, in practice the oil's bubble point pressure limits the sampling pumpout rate. However, if a tester is equipped with more than one probe, as the new tester is, pumping through both probes can increase sampling rates. Additionally, if the sampling probe is placed near a permeability barrier, a further improvement on sample quality can be expected. All of these options can potentially improve sample quality and reduce pumpout time.

To study these effects a sensitivity analysis has been performed using the simulator to determine the impact sampling procedures have on sample quality. PWFT log examples are used to compare with the simulated results.
Planning A Successful Accident Preventional Program
Authors: Homewood C.
Published: December 2007

HOMEWOOD, C., ARABIAN AMERICAN OIL COMPANY

Introduction

Accidents have plagued man since the beginning of time. They have caused him injury. They have caused him property damage and loss. And sometimes they have cost him life. Accidents often have been considered inevitable. In one sense, they are—they are the inevitable result of human failure.

Accidents have changed the course of history. They certainly change the course of our life if we are the injured or our property is lost or damaged. Accidents have increased to such a degree in modern life that they require our best efforts to prevent them. Much is available in the literature of the world on how to prevent accidents, and I am sure this paper will give nothing new in accident prevention. But if it re-emphasizes safety fundamentals, it will serve a useful purpose.

There has been some tendency to limit accident prevention to study of injury-producing ones and to overlook accidents that cause damage or loss of property. This tendency is understandable. Personal injuries are rightly more demanding of our attention than destruction of property. But this limited view has delayed progress in accident prevention.

I think it is appropriate to define the word "accident" as a professional safety engineer uses it:

"An accident is any unexpected event that interrupts of interferes with the orderly of production, activity, or process."

Under this definition, an accident may cause damage to equipment or material or cause a production delay without resulting in an injury. It is here that the campaign to prevent accidents must start for almost every accident has the potential of causing injury.
Effect of Pore Pressure and Stress Path on Rock Mechanical Properties for HPHT Application
Authors: Skomedal E. , Jostad H. P. , Hettema M. H.
Published: December 2007

A laboratory testing program was performed to investigate the behavior of the sandstone of an HPHT reservoir when subjected to realistic in-situ stresses, pore pressures and stress changes due to production. Volumetric changes, stress path effects, plastic deformation and strength were included. It was found that the Terzaghi effective stress definition was most suitable to handle the different mechanisms. Relevant material properties were defined, and a basis for geomechanical engineering of drilling and production of the HPHT reservoir was established.
Mud Chemistry Effects on Time-Delayed Borehole Stability Problems in Shales
Authors: Fjær Erling , Holt Rune M. , Nes Olav-Magnar , Sønstebø Eyvind F.
Published: December 2007

A combination of small sample testing and numerical modelling offers a powerful tool for identification of mud chemistry effects on wellbore stability in shales. The tool allows for modelling of how the stability limits for the mud-weight varies with time, based on measured time scales and magnitudes for the various processes involved. It may also assist in estimation of the optimal amounts of chemical additives in the mud.
Predicting Volumetric Sand Production in Weak Reservoirs
Authors: Chin L. Y. , Ramos G. G.
Published: December 2007

In general, sand production in oil/gas reservoirs in weak formations has an adverse impact on production costs. For efficient reservoir management, predictive tools are needed to quantitatively mitigate and control sand production. A fully coupled sand production model that integrates geomechanics and fluid flow was developed to quantify volumetric sand production during the early drawdown period (a few days), bean-up, as well as in the depletion period (a number of years).

First, we compared simulation results from the proposed model to sand production data from full-scale laboratory perforation sanding tests for model verification. Then, we employed the developed model to evaluate the key variables that govern volumetric sand production. This study indicates that sand production in weak reservoirs is influenced by a number of variables. These include rock strength, flow rate, oil viscosity, and producing time. The simulation results relating cumulative sand production and sand production rate to these important variables are presented. Descriptions of the volumetric sand production model (formulations, constitutive equations, solutions procedures) are also presented.

The study suggests that the proposed model may be used to generate quantitative information for predicting volumetric sand production. This provides a tool for sand-management in exploiting the weakness of sanding-prone scenarios.
Experimental Observation of Injection Rate Influence on the Hydraulic Fracturing Behavior of a Tight Gas Sandstone
Authors: Zeng Zhengwen , Roegiers Jean-Claude
Published: December 2007

It has been widely accepted in hydraulic fracturing that the higher the pressurization rate, the higher the breakdown pressure. However, linear elastic fracture mechanics (LEFM) suggests the opposite. In an effort to clarify this "injection rate paradox," three controlled laboratory hydraulic fracturing experiments were conducted using different injection rates. These tests showed that the higher the injection rate, the lower the breakdown pressure. Further investigations indicated that the elastic- and poroelastic- models were not able to properly predict the observed breakdown pressures. Using Griffith's energy balance concept, an LEFM-based breakdown pressure model was derived which gives satisfactory predictions.
Equilibrium Test - A Method for Closure Pressure Determination
Authors: Weng X. , Pandey Vibhas , Nolte K. G.
Published: December 2007

Minifracs are routinely pumped before fracturing treatments to determine the in-situ fracturing parameters such as fracture closure pressure and fluid leak-off coefficient. These parameters are essential for design adjustment, pressure match, and fracture dimension estimate. The method most commonly used for determining closure pressure is pressure decline analysis during the shut-in period, using G-function plot, square-root time plot or other plots. Unfortunately, the shut-in decline data is often difficult to analyze and can yield inconsistent and erroneous closure pressures.

A new injection test for closure pressure determination, called "equilibrium test", is described in this paper. In the test, a fluid is first injected at a normal fracturing rate for a period of time to create a hydraulic fracture, and then pump rate is dropped to a small rate and held constant. The treating pressure will initially decline as in the conventional shut-in decline, but will gradually level out and start increasing, when equilibrium between the small injection rate and the leak-off from the fracture is reached. The pressure response can be easily analyzed to obtain an estimate of closure pressure. Fluid efficiency can also be estimated from the decline slope. A detailed discussion of the method, analytical calculations for determining the closure pressure and several field cases are presented in this paper.
Discrete Element Approach for the Wellbore Instability of Laminated and Fissured Rocks
Authors: Yamamoto K. , Shioya Y. , Uryu N.
Published: December 2007

A laminated and fissured formation around a horizontal borehole is modeled as a combination of intact rock blocks and permeable fractures with a DEM code. The model is used for understanding the mechanism of rock failure problems observed in a shale formation of an offshore field. Different mud weights and stress conditions are applied to the model to simulate the rock failure around deviated holes in laminated and fissured shale.

The numerical simulation shows that shear failure along the bedding planes is the predominant mode of collapse of the hole when mud under pressures penetrate into bedding planes on which shear stress is applied. The severity of wellbore instability varies with stress states and wall conditions. The effect of a plugging agent in mud is verified by comparison between permeable and impermeable wellbore models.
Estimation of Stress Profile with Depth from Analysis of Temperature and Fracture Orientation Logs in a 3.6 km Deep Well at Soultz, France
Authors: Ito T. , Fujii R. , Evans K. F. , Hayashi K.
Published: December 2007

We presented a new method for stress measurements which is based on the hypothesis that fractures which are critically-stressed for frictional sliding in the current stress field tend to permeable and those which are not critically-stressed tend to be impermeable. Fracture depth, dip and strike can be detected from borehole imaging logs such as BHTV/UBI or FMI/FMS. By comparing the depths of fractures and those of thermal anomalies detected on temperature logs, we can identify which of the fractures are permeable. Stresses on fracture planes can be estimated from the fracture orientation provided that the state of in-situ stress is assumed. Therefore, knowledge of which fracture orientations tend to be permeable and hence support critical stress states, and which fracture orientations are not allows us to make a grid search over possible states of stress to identify the stress state that best satisfies the observations and hypothesis. A simple description of the stress states is necessary. Assuming that one principal stress is vertical and equal to the overburden and pore pressure is known, the stress states are defined by three unknowns given by the two depth gradients of the two horizontal stresses, and the orientation of the maximum horizontal stress. The range of admissible stress states can be further reduced by considering the strength of the bulk rock. We applied the method to estimate stress state about a 3.6 km deep well in granite at the Soultz Hot Dry Rock test site. Fractures and thermal anomalies detected in the depth range of 2850∼3500 m were used for the estimation. Results indicate that the stress regime is one of normal/strike-slip faulting, consistent with the fault plane solutions of induced and regional earthquakes. The predicted profile of minimum principal stress magnitude agrees with that determined from the hydrofracture method. The inferred orientation of the maximum principal stress differs from the best available estimate (defined by thermally-induced tension fractures) by 20∼30°. The example demonstrates that the method can yield useful estimates of the state of stress at great depth from relatively common data of temperature, borehole imaging, and density logs without requiring any additional input from expensive test. The method can also be applied in high temperature environments where conventional approaches to stress estimation cannot be applied.
Challenges for Monitoring and Verification of Drill Cuttings Reinjection Performance
Authors: Abou-Sayed Ahmed S. , Guo Quanxin , Wang Gary , McLennan John D. , Zaki Karim
Published: December 2007

To a certain extent, the success of drill cuttings reinjection (DCRI) has been serendipitous. Aggressive operational parties initially implemented the technique with support from far-seeing researchers. With the favorable economics incentive along with successful and safe implementations, drill cuttings reinjection has been further refined over time with established methodologies for attempting to more precisely predict placement of large solid volumes. There is a need now for verification and accurate monitoring of the process.

This paper reviews standard technologies for monitoring cuttings placement; including pressure-time evaluation during and following injection using conventional methodologies, pressure transient evaluation technologies during and between batches. These techniques include interference techniques where appropriate, microseismic monitoring, tiltmeter surveys and logging methods. Future challenges and developments of each relevant technology are suggested in more detail. For example, tiltmeter methodologies have been successfully used in many situations but there remain issues in certain environments, i.e., in some layered scenarios. A good example of this relates to the difficulties that might be encountered in inverting tiltmeter data in arctic regions where DCRI takes place below an extensive permafrost layer. Another example relates to refining concepts for predicting multiple fracture geometries. Most practitioners are familiar with the disposal domain concept where batch-injected fractures are attributed to a simplified and regular three-dimensional domain, with no specific indication of individual fracture morphology. To date, precise prediction of domain geometry from pressure signatures or surface tilts has been weak. Simple methods are presented for identifying from pressure records or surface profiles the three-dimensional extent and near-well azimuths of multiple fractures.
Real-Time 4D Passive Seismic Imaging of Hydraulic Fracturing
Authors: Maxwell S. C. , Urbancic T. I. , Demerling C. , Prince M.
Published: December 2007

Passive microseismic imaging of fracture growth during hydraulic fracturing provides detailed images of the fracture geometry, including fracture dimension, orientation and complexity. The technology can be applied in real-time, during the stimulation, to provide time-lapse, 4D seismic images of the fracture growth. Here we present a number of case studies that illustrate how these images can then be used to improve the implementation of intended stimulation designs. The case studies demonstrate the feasibility of assessing the effectiveness of flushing an unexpected screen-out, imaging proppant placement, and controlling fracture geometry.
Coupled Geomechanics-Fluid Flow Modeling: Effects of Plasticity and Permeability Alteration
Authors: Yale D. P.
Published: December 2007

Yale et. al.1 showed significant differences between "uncoupled" reservoir simulations of a highly compressible (but elastic) reservoir and the same model run with deformation and fluid flow "coupled" together. This paper utilizes a similar model but investigates the effect of plasticity of the reservoir rock and alteration of permeability with deformation on these coupled simulations.

The coupled simulations show that plasticity significantly increases the compressibility of the rocks and the compaction drive energy of the reservoir. The initial stress state of the reservoir is shown to have a large effect on the degree of plasticity and the degree of depletion for the same amount of fluid withdrawal and the same rock properties.

Modeling the change in permeability with deformation of plastic sands shows an extremely large effect on near wellbore pressure drawdown and deformation over normal reservoir simulations. The coupld geomechanis-fluid flow simulations show very strong interaction between pressure drawdown, plastic strain, and permeability.