bluuebunny/crossref_metadata_2025 huggingface dataset:
Vibration Analysis, Model Prediction, and Avoidance: A Case History
Authors: Samuel G. Robello , Schottle Gary , Gupta D. B. , Drilling Halliburton
Published: December 2007

In recent years, there has been a greater emphasis on technical limits with respect to drilling operations. Oil and gas companies strive to be amongst the highest ranked in operational efficiency with respect to industry related benchmarking statistics. Increasingly complex drilling scenarios, both surface and down hole, coupled with extremely high operating day-rates provide a challenging environment for those partaking in such operations. The risks are high, but the rewards are as well. Companies that can operate efficiently in such scenarios will most certainly reap the rewards.

Understanding technical limits and achieving operational excellence requires proper planning. Unfortunately, proper planning is only a part of the equation. The complexity of the subsurface environment generally results in deviation from planned operations. These deviations may result in significant non-productive time or in equipment failure. Reducing such incidents requires knowledge that the incident took place. Knowledge that the incident took place requires accurate data mining and retrieval as there may be significant time between operations, and knowledge transfer can be lost due to personnel changes. Additionally, an understanding of the root cause of an incident needs to be understood to prevent future incidents. This is generally more difficult to get a handle on. Applying post failure analysis utilizing engineering software applications is an essential part of determining the causes of non-productive time incidents and equipment failures. One could also surmise that it is a critical part of the planning process even though the analysis is after the fact. Reviwing lessons learned is a critical part of any planning process.

In high risk, high cost environments, such as ultra-deep, ultra-deep waters, refining advanced technologies for successful completion of wells is paramount. Challenges are still very much associated with complex BHAs (bottomhole assemblies) and with the vibration of the drillstring. The more widespread use of sophisticated downhole tools — for both directional telemetry and for logging while drilling applications (as part of the front line data acquisition system within the drilling process) — has meant that reliability is of prime importance1–5. This paper presents and validates an existing model to predict severe, damaging vibrations. The paper also reviews analysis techniques and guidelines to successfully avoid the vibration damage to downhole tools and their associated down hole assemblies.
Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing Wells Using Permanently Installed Fiber-Optic Monitoring
Authors: Krawchuk P. , Beshry M. A. , Brown G. A. , Brough B.
Published: December 2007

During the start-up and early operation of horizontal steam assisted gravity drained (SAGD) wells, it is important to understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood, the distribution of steam, injected either at the heel or toe of the steam injector, can be adjusted to optimize the startup and early operation of the SAGD pair.

Total E&P Canada permanently installed optical fiber along their first Joslyn SAGD production well to monitor the temperature profile continuously during startup and production. Initial steam circulation and production occurred in 2004.

The acquired data shows that large temperature gradients exist across the wellbore during startup and early production, which is consistent with data from the observation wells. The injector-producer interval between SAGD wells was modeled with a thermal reservoir model to understand the influence of fluid viscosity, water cut, and permeability on fluid flow and the fiber optic measured temperature response.

By varying the injector-producer reservoir temperatures until the model temperature matches the measured distributed fiber optic temperature, it is possible to calculate the fluid viscosity in the inter-well region and consequently the flow distribution along the producing well.

Injector-producer temperature, which dictates the bitumen viscosity, was found to be the main parameter controlling flow in the injector-producer region. The results highlight the need for distributed temperature measurements in SAGD wells to facilitate understanding of the temperature response over time. The analysis demonstrates that it is possible to determine the flow profile from the distributed temperature measurement and thus optimize the injection of steam into the heel or toe of the injector well.
Bridging the Gap: Challenges in Deploying Leading Edge Geomechanics Technology to Reducing Well Construction Costs
Authors: Mody Fersheed K.
Published: December 2007

Over the past two decades Geomechanics has made substantial contributions to the petroleum industry in the following areas: reducing well construction costs1,maximizing production2, andincreasing the life of the well.

Currently the industry is venturing into more complex extended reach wells3, deeper water, higher pressure higher temperature environments, sub-salt settings4, lower pore pressure/fracture gradient margins, depleted zones5, fractured carbonates2 and fractured reservoirs6, environmentally sensitive areas, and many other difficult to develop situations, as illustrated in Figure 1.

Geomechanics will play a significant role in addressing these added challenges. The high price of oil is here for a long time. Our technical responsibility is to make sure that the unit development cost (UDC) to produce this oil is contained and subsequently lowered with aggressive application of relevant technology and a knowledgable workforce adept at applying this technology.

Being prepared to deal with the following issues will be integral to success: borehole (in)stability7–12,lost circulation13,14,stuck pipe15,sand production16,17,casing collapse18,19,well failures20,formation damage21,sub-salt related issues2.

Each of these problems can strike at any time if we are not vigilant and pro active in avoiding them. Prevention at the outset is more cost-effective than fixing these issues later. I propose we have to bridge the gap between people and technology to be effective in this age of oil industry geomechanics. See Figure 2.

Controlling Costs

Geomechanics-related issues cost the industry billions of dollars.22

We cannot afford, as an industry, to lose billions of dollars on Geomechanics-related non-productive time (NPT) and associated loss in revenues.32

Over the past decade, for the drilling industry on an average twenty two percent of the drilling budget can be attributed to wellbore related NPT. Fifty percent of this NPT is associated with geomechanics related (i.e. wellbore stability, Lost circulation, stuck pipe, etc.) issues.1, 811, 22, 32

In spite of advances in technology, this NPT percentage associated with borehole related problems has not drastically changed over the past decade. NPT percentage of the total drilling budget is much too high and must be lowered to a more acceptable level.

Also further scrutiny of the NPT data suggests a trend, that approximately 90% of costs can be attributed to a small percentage of wells that are highly complex. When these wells have problems, the cost escalates. See Figure 3. Hence, it is critical to manage the available geomechanics resources in the most optimal manner. It is important to identify the high mechanical-risk index wells and get the right geomechanics resources committed – both personnel and data collection – early in the planning stages of the well construction and utilize these resources throughout the well delivery cycle.
The Texture of Acidized Fracture Surfaces—Implications for Acid Fracture Conductivity
Authors: Malagon C. , Pournik M. , Hill A. D.
Published: December 2007

In an acid fracturing treatment, fracture conductivity is created by differential etching of the fracture surface by the acid – without non-uniform dissolution along the fracture face, the fracture will close after pumping ceases, and little lasting conductivity is created. In spite of this critical role of differential etching on the creation of fracture conductivity, little is known about the texture of the fracture surface created during acid fracturing, and the dependence of this texture on the acidizing conditions. To study this important aspect of the acid fracturing process, we developed a new surface profilometer for accurately and rapidly measuring the surface profile of a rock sample, and have used it to measure fracture surfaces after acidizing.

The profilometer measures the distance to the rock surface with a laser device that measures distance with an accuracy of 0.001 in. The rock sample is mounted on a servo table that automatically moves the sample in selectable increments that are typically 0.025 in. With this device the surface of a standard API fracture conductivity sample can be scanned in a few hours and a digitized profile image can be obtained. This digital image is used to quantitatively characterize the etched surface topography.

We have measured the etched fracture surface profile for a wide range of acidizing conditions. The etched surface characteristics depend very strongly on the acidizing conditions, including acid type and strength, solution apparent viscosity, velocity in the fracture, and leakoff rate, and rock type. Results for typical acid fracturing fluids and conditions are presented as well as recommendations for fluid systems that create the most small scale differential etching.
Coupling of Downhole Dynamics Recorder Enhances System-Matched Approach to Drill-Bit Design and Application With a Specific Rotary-Steerable System
Authors: Barton S. , Lockley R. , Stroud D. , Peach S.
Published: December 2007

The combination of the large number of rotary-steerable systems (RSS) currently available and the variety of well trajectories in which they are applied requires a customized range of drill bits to optimize system performance. A clear understanding of the specific tool operation, combined with in-depth modeling and physical testing, is the ideal approach for determining the demands placed on the drill bit and thus deriving its key characteristics.

This paper describes a series of tests that were performed at a purpose-built drilling facility to examine the variation in directional response with different bit features. Steerability is one of the key criteria involved in RSS bit design, but stability is of equal importance, particularly in ensuring good-quality, gauge borehole for maximum steering potential. To monitor the testing, a proprietary downhole dynamics recorder was used. The recorder consists of a small, sophisticated electronic measuring device that can be either housed in a sub or positioned in a specially modified housing within an existing drillstring component. The recorder was used to gather actual downhole data at a high frequency sample rate to determine both the lateral and torsional stability of the drill bit and RSS assembly with different wellbore trajectories and parameters.

Results identified that specific gauge features are crucial to the directional response of the RSS tool. In addition, the dynamics recorder allowed quantitative assessment of stability versus steerability of the critical drill bit features tested. Lessons learned from this laboratory testing have been taken to the drilling environment with excellent field results, demonstrating that matching the bit to a specific RSS tool as part of the system delivers proven drilling success.
Comprehensive Drill-Rate Management Process To Maximize Rate of Penetration
Authors: Dupriest F. E.
Published: December 2007

The operator's drill rate management process is designed to maximize rate of penetration (ROP) in every foot of hole drilled. Due to its quantitative nature and the degree to which it is incorporated into all phases of the drill well process, the operator believes it to be the industry's first comprehensive ROP design process. The workflow is being implemented uniformly across an organization drilling approximately 4.5 million feet of hole per year in a wide range of rock types, directional profiles, and international locations. The results to date have been similar in most applications with significant gains in ROP, bit life, and reduction in tool failures related to vibrations.

The workflow evolved from surveillance techniques the operator developed to utilize Mechanical Specific Energy (MSE) surveillance to evaluate drilling performance in real-time(1),(2). MSE surveillance proved to be an effective aid in identifying bit and system inefficiency. However, having this knowledge does not ensure the team knows why the inefficiency is occurring, or how to correct it. There are organizational processes that must also be considered when mitigation of the problem involves increased mechanical risk, significant changes in established practices, or a high level of technical training. MSE is a technology, while the ROP management process is a broad workflow designed to ensure MSE and numerous other sources of data are used effectively to maximize ROP. Consistent implementation of the workflow has been shown to achieve consistent increases in ROP. The key elements of the workflow required to achieve this performance are discussed.

Over 40 categories of ROP-limiters have been identified, of which only 4 are directly related to the bit. The ROP in a large portion of footage drilled is constrained by factors other than bit performance, which are referred to as non-bit limiters. The workflow addresses both bit and non-bit limiters equally, and includes a simple model to aid drill teams in prioritizing the large number of potential ROP-limiters so resources available for surveillance and redesign are used most effectively.

Performance improvements have been sustained since the staged rollout began in late 2004, and additional gains are continuing. Performance data is included, as well as a discussion of key implementation learnings.
Development of Low-Order Controllers for High-Order Reservoir Models and Smart Wells
Authors: Gildin E. , Klie H. , Rodriguez A. , Wheeler M. F. , Bishop R. H.
Published: December 2007

Recently, the oil industry has started instrumenting and deploying various controls for the enhancement of hydrocarbon extraction. However, due to system complexity, data acquisition and, in turn, decision making, are still issues to be resolved in large-scale reservoir management. A very challenging large-scale control problem that has emerged recently is the real-time control of smart wells. A fundamental reason for using feedback control in this setting is to achieve desired performance in the presence of external disturbances and model uncertainties.

This work introduces iterative Krylov subspace projection (KSP) methods to generate low-order feedback controllers for smart wells employing high-order reservoir models. The main motivation for using these methods is to enable the efficient computation of low-order reservoir models derived from the highly sparse structure of fluxes and pressure coefficients after discretization. Compared to other model reduction methods, such as modal decomposition, balanced realization, subspace identification and the proper orthogonal decomposition (POD), the proposed approach is very efficient since it is fundamentally based on sparse matrix-vector products. For a problem size of n simulation gridblocks, the KSP method presents a complexity of O(n2k) (or even O(nk), by exploiting sparsity), where k is the number of iterations required to generate the low-order model. This is highly desirable for the design of timely low-controller mechanisms in smart wells.

We illustrate the potential of the method by linearizing an oil-water model and showing how to establish stability and error bounds for production responses under certain perturbations. We also discuss how the method can be extended to cases of non-stationary and nonlinear fluid coefficients.
Modeling Low-Salinity Waterflooding
Authors: Jerauld G. R. , Lin C. Y. , Webb K. J. , Seccombe J. C.
Published: December 2007

Low salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is controlled to improve oil recovery over conventional higher salinity waterflooding. Corefloods and single well chemical tracer tests have shown that low salinity waterflooding can improve basic waterflood performance by 5 to 38%. This paper describes a model of low salinity flooding that can be used to evaluate projects, shows the implications of that model, demonstrates its use to represent corefloods and single well tests as well as field scale simulations, and gives insight into the reservoir engineering of low salinity floods.

The model represents low salinity flooding using salinity dependent oil/water relative permeability functions resulting from wettability change. This is similar to other EOR modelling and conventional fractional flow theory can be adapted to describe the process in one dimension for secondary and tertiary low salinity waterflooding. This simple analysis shows that while some degree of connate water banking occurs it need not hinder the process. Because mixing of injected water with in situ water delays the attainment of low salinity, potentially preventing attainment of low salinity all together if very small slugs of low salinity water are used, care must be taken in representing mixing appropriately in interpreting data and in constructing models. The use of numerical dispersion to represent physical dispersion in 1D, radial and pattern simulations of this process is demonstrated, i.e. coarse simulations are shown to give the same result as fine grid simulations with appropriately large physical dispersion. In many applications, the fine grid simulation necessary to represent appropriate levels of dispersion is not practical and pseudoization is necessary. We demonstrate that this can be done by changing the salinity dependence and shapes of relative permeability curves.
Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions
Authors: Omar M. I. , Ali A. Md , Ali Z. , Parapat A. , Speck W. , Parta E.
Published: December 2007

Coiled tubing has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and long section of horizontal wells under live condition, where slickline and E-line have difficulties.

This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak field, one of the gas field operated by Malaysia National E&P Company, Petronas Carigali Sdn Bhd.

Since the beginning of Resak Field production, coiled tubing has been used to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed by high CO2, H2S production and improper well clean up contributed in the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures.

CTU with 1.5" CT reel was used to convey 140 ft of 2-7/8" gun due to crane and platform deck loading limitation. The small CT size and large gun conveyance required extra precaution since the presence of gun shock during perforation may affect the CT integrity. Therefore supporting perforating software was run in advanced to optimize gun selection where both operational risks and production objectives were taken into consideration. Coiled tubing forces simulation was also used to determine the ability of the gun assemblies to be safely conveyed into the target sands. In addition to that, one of the unique features from the gun assemblies was the selection of electronic firing head over a conventional or standard drop ball mechanism. This tool utilized coded sequence created from variation of surface pump rate to generate its firing command, providing reliable gun activation where as the drop ball mechanism in the past was found to have some operational difficulties.

Lastly, this paper also mentions the proper selection of zonal isolation method that can withstand the wellbore condition, providing adequate isolation whilst able to be retrieved for future production requirements. The result of those engineering studies managed to overcome the operational failures in the past and at the same time was able to meet the production objective.

Project Result

After performing the coiled tubing operation by isolating J10.2 with inflatable bridge plug and perforating J10.1 with deep penetration gun, the well managed to be produced at 22.7 MMSCF/D & stabilized at 48 MMCSF/D (23 % choke size) with total gain of 41MMSCF/D which was higher than the expected gain of 35 MMSCF/day (Figure 1). Currently the well is the highest producing well in Resak field with stable production at 49.8 MMSCCF/D. Figure 1Production Data before and After CT Perforating
Challenges for Everyday NMR: An Operator's Perspective
Authors: Akkurt R. , Kersey D. G. , Zainalabedin K.
Published: December 2007

State-of-the-art Nuclear Magnetic Resonance (NMR) applications can be classified into two categories: (1) basic applications designed for total porosity, bound water and permeability, (2) advanced applications that address hydrocarbon type, viscosity and flushed zone hydrocarbon saturation, amongst some others.

An NMR log designed for basic applications – especially a T1 log – can provide accurate porosity information in shaly sands and complex carbonates; answer questions related to reservoir quality and producibility; and easily identify gas or tar zones. Given the obvious benefits of such information for routine petrophysical analysis and timely business decisions, one would assume that NMR logging would already be an everyday phenomenon in formation evaluation. Unfortunately, NMR has yet to enter the main stream of everyday logging: it is still considered a specialty, requiring the involvement of experts from the planning to the interpretation stages.

Partially due to historical reasons, but more so for cost justification and product differentiation, service companies have traditionally focused on advanced applications. Hence, despite significant advances made in all phases of the technology, concentrating on sophisticated methodologies has resulted in slow logging speeds and high costs, in addition to complex data acquisition, processing and interpretation procedures.

Turning the everyday-NMR concept into a reality will require standardization of the service and proper hardware that is free of the limitations of the existing tools. The main objective of this paper is to discuss specific strategies to achieve the everyday-NMR goal for wireline and LWD logging. The proposed strategies include not only the technical requirements, but also the initiatives required from both the operators and service companies.
IOR Strategies in Brownfields of Mehsana Asset, North Cambay Basin, India
Authors: Pratap V. , Sood R. K. , Ram Binay
Published: December 2007

Mehsana tectonic block in North Cambay Basin is a fairly well explored, productive block where oil is both heavy and light. The block is now in a mature stage of exploitation associated with EOR techniques. Since oil production commenced in 1968–69 with a meagre 26 tons/day, the main fields have been developed through well planned development schemes. The recovery factor is intimately associated with reservoir heterogeneities, manifestation of environments of deposition, drive mechanism, fluid properties, pool size and depth of occurrence. These inherent characteristics are further influenced by reservoir management practices. The decline in oil production of the nineties was arrested and consistent growth since 1999 has been effected through efficient reservoir management practices accentuated by commencement of induction of technology.

IOR strategies with the objective of enhancing (i) Recovery and (ii) Production; are in vogue in the asset and began with revisiting the field geological and reservoir models. Strategies include:(a)Infill drilling recovery mechanism;(b)Initiation/Modification of water injection;(c) Enhanced oil recovery through Insitu combustion technique in heavy oil fields (d) High technology drilling like horizontal, high-angle-high drift wells and ultra-short radius drain holes and (e) By passed reserves identification and recovery methods like microbial methods addressing recovery enhancement. Production sustenance and enhancement through (a) Artificial Lift optimisation (b) Massive hydraulic fracturing (c) Well bore chemical stimulation in heavy oil fields and paraffin intervention in light oilfields(d) Flue gas utilization (e) Unique flue gas shut off in heavy oil belt (f) Improved sand control measures and (g) Improved sick well treatment are in place. The results from these schemes in terms of incremental oil are encouraging and have helped increase oil production marking a paradigm shift from earlier practices. Plans are afoot to foster improved production growth rate to increase ultimate recovery in tune with the newly set standards and accelerate brownfield development.
New Era of History Matching and Probabilistic Forecasting—A Case Study
Authors: Selberg S. , Ludvigsen B. E. , Diab A. , Harneshaug T.
Published: December 2007

This paper presents a case study using optimization technology to improve the reliability of reservoir simulation models. Global optimization techniques have been applied to assist the history matching (HM) performed. Evolutionary Algorithms and deterministic optimization schemes are integrated into a workflow controlling a large number of parallel reservoir simulations. Results are analyzed and compared to traditional HM to identify the potential added value and increased efficiency. Focus is given to the reservoir engineer who is in full control over the optimization process and interacts frequently as he/she acquires more information and improved understanding of subsurface uncertainties.

The case study demonstrates the benefit and added value of utilizing a computer assisted HM workflow. Pitfalls of using a traditional workflow are illustrated.

The paper focuses on a gas condensate reservoir where the most important well had proven to be difficult to match using a traditional manual HM approach. The sensitivities of a large number of input parameters were investigated, and an optimization scheme was set up in order to generate alternative HM realizations of the simulation model.

Alternative models were generated using a wide variety of input parameter combinations. The entire study was conducted over a two week period, where approximately 7000 full field reservoir simulations were run. A large number of simulation models were matched within the uncertainty of the observed data, and these acceptable matches gave a wide range of recoverable reserves from the field. The first match that was found proved to be outside of the initial uncertainty range, clearly verifying the need for more than one HM model to cover the uncertainty found in most producing reservoirs. This illustrates the non-uniqueness of simulation models and the danger of relying on one deterministic model.
Experimental Investigations and Findings on Deep-Well Drill-Collar Failures To Improve Drilling Downtime in Teikoku Oil Co.
Authors: Ikeda Shoichi , Tsuruta Makoto
Published: December 2007

Teikoku Oil Company has experienced frequent and continuous drill collar failures on drill collar connections in deep wells, causing significant expense and inefficiency. Investigations about drill collar connection failure have included metallurgy, corrosion and stress analyses to elucidate the cause of failure happened on many of the drill collars.

Several metallurgical inspections reveled that all failed drill collars were produced under proper quality control. Sulfide stress corrosion cracking and hydrogen brittle wear were also considered, but any evidence was not detected.

Although stress analyses on connections both of pins and boxes were done, the values of triaxial stress showed that all failed drill collar have been used under the normal stress conditions. Both of bending stresses ratio and stiffness stresses was satisfied API RP7G respectively.

The remaining considerable cause of failure was fatigue failure. Teikoku Oil Company carried out a number of drill collar failures reviews on each size of drill collar, reviewing a significant number of wells.

The result of investigations showed that total drilling revolutions of drill collar till failure were very similar numbers. After these investigations, standards for the maximum total drilling revolutions of drill collar to prevent fatigue failure were decided for each size of drill collar. After the critical total revolutions, all drill collars used for drilling were sent to the maintenance shop for magnetic particle test.

Teikoku found that even though magnetic particle test was done, drill collar failure still occurred. Once establishing the critical total drilling revolutions for drill collars, drill collar failure significantly decreased. The company continues to perform magnetic particle tests by drilling crews at rig site for cost saving without any problem.
Achieving the Vision in the Harweel Cluster, South Oman
Authors: O'Dell M. , Soek H. , van Rossem S.
Published: December 2007

With high GOR and sour gas in South Oman, re-injection schemes were considered for the recently discovered reservoirs of the Harweel Cluster in South Oman. With the light oil and very high pressure, re-injected associated gas is nearly miscible with the reservoir oils. A program of study was planned to coincide with further appraisal and bringing some of the reservoirs onto production. After five years of study and simultaneously three years of development and two years of production from a "Phase 1" project, a Phase 2 production and miscible gas injection development has been approved by shareholders and has started. The Phase 2 development is one of the largest petroleum development projects ever undertaken in Oman.

This paper describes the strategies employed by the team responsible for developing the reservoirs of the Harweel Cluster. The original vision has been bolstered by substantial near field discoveries during the last five years. The appraisal challenges, the emerging study results, and reservoir pressure and production performance have required only minor adjustment to the original development concept.
The Effect of Fixed-Cutter Bit Design Features on the Steerability and Field Performance of a Point-the-Bit Rotary-Steerable System
Authors: Peach S. , Stroud D. , Barton S. , Lockley R.
Published: December 2007

This paper describes how extensive testing has allowed the determination of a link between cutting structure geometry, gauge pad configuration, and achievable hole curvature or steerability. For a specific point-the-bit system, the tests have shown that steerability of the bit is not substantially dependent upon the cutting structure geometry; rather, the nature and extent of gauge pad features are crucial to the directional response of the system. Gauge pad bearing efficiency must be high while simultaneously allowing the cutting structure to tilt as directed by the rotary-steerable system (RSS).

The several case histories presented, from operations in the North Sea and offshore Indonesia, verify the results of laboratory tests regarding the relationship between design features of fixed cutter bits and steerability of a point-the-bit RSS. Furthermore, these case histories demonstrate that a point-the-bit RSS, together with an optimized bit design, can lead to improved drilling efficiency in providing good directional response, high rates of penetration (ROP), excellent-quality wellbore smoothness, improved loggingwhile-drilling (LWD) log response, and ease of completion.
Lessons Learned and Guidelines for Matrix Acidizing With Viscoelastic Surfactant Diversion in Carbonate Formations
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , Devine C. S.
Published: December 2007

To conventionally drill, complete and produce horizontal and multilateral wells with zero skin is not an easy undertaking. Much attention has been given to "best oil field practices" in both drilling and production processes, but the reality is that formation damage will often have to be addressed sometime during the life time of the well.

Formation damage due to drilling and scale formation is common problem in carbonate reservoirs that can be re-mediated using chemical means. The success of any treatment however, requires a complete understanding of the problem and a solution that will address the majority of the damage. The solution evolves with time and experience. Extended reach intervals with variable permeability complicate the process. Reservoir and fluid characteristics, cleanup fluid chemistry, and operational considerations must always be considered.

The acidizing experience and an improved understanding of how to effectively treat long and heterogeneous intervals in carbonate formations is rapidly evolving in Saudi Arabia. Water injectors, oil producers and wastewater disposal wells have been treated and are reviewed in this study. These wells have different configurations including: vertical, horizontal, extended reach, and multilateral with open hole and cased completions. Several acid placement and diversion techniques have been applied and a specialized treatment package was developed based on the latest coiled tubing and chemical diversion technologies. Laboratory studies, lessons learned and specific design guidelines from both successful and less than expected well treatments are highlighted in this work.
Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Production Rate
Authors: Nasr-El-Din H. A. , Al-Driweesh S. , Bartko K. , Al-Ghadban H. , Ramanathan V. , Kelkar S. , Samuel M.
Published: December 2007

The deep, tight carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular, in-situ gelled, and emulsified acids, have been used in order to achieve optimum fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressure of the formation.

A new generation of viscoelastic surfactant-based acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in-situ gelled acid.1 However, the wells treated with viscoelastic surfactant based acid did clean out in a shorter period of time.

The main objective of this study was to compare the "long term" production results obtained from five wells treated with the surfactant-based acid with off-set wells treated with in-situ gelled acids. This paper provides for the first time long term production data evaluation following acid fracturing using surfactant-based acids. It also compares the performance of two main acid systems based on field data.

The evaluation of acid fracturing treatments with in-situ gelled acid systems and surfactant-based acid systems suggest that there was no significant variation in the design and the execution of both the viscoelastic and in-situ gelled acid treatments. Among the 5 wells treated with surfactant-based acid, 4 of them showed better long-term production performance over a 2-3 year period compared to their offset wells. In the short-term (nearly 3 months production), 2 wells treated with viscoelastic acid showed no difference in production performance compared to their offset wells.
Gas Condensate Wellbore Modeling Using a Fundamental Approach
Authors: Sadegh A. A. , Zaghloul J. S. , Adewumi M. A.
Published: December 2007

Multiphase flow in the wellbore poses a challenge for production engineers since characterization of prevailing flow regime determines the appropriate pressure drop calculation method. The problem is further complicated when the flowing fluid undergoes phase changes. The key objective was to develop a wellbore flow model based on sound physical principles, incorporating current hydrodynamic and thermodynamic methods.

The model developed comprises a flow pattern detection routine, hydrodynamic model, and an equation-of-state-based phase behavior package. The model was extensively tested with 30 field cases, proving to accurately predict pressure drop for single and two-phase (gas/condensate) flow giving an average absolute error of 6.3%.
Deconvolution of Multiwell Test Data
Authors: Levitan M. M.
Published: December 2007

The deconvolution analysis technique that evolved with development of the deconvolution algorithms by von Schroeter et al.1 and Levitan et al.2, 3 became a useful addition to the suite of techniques used in well test analysis. This deconvolution algorithm, however, is limited to the pressure and rate data that originate from a single active well on the structure. It is ideally suited for analysis of the data from exploration and appraisal well tests. The above mentioned deconvolution algorithm can not be used with the data that are acquired during startup and early field development that normally involve several producing wells.

The paper describes a generalization of deconvolution to multi-well pressure and rate data. Several approaches and ideas for multi-well deconvolution are investigated and evaluated. The paper presents the results of this investigation and demonstrates performance of the deconvolution algorithm on synthetic multi-well test data.
Errors Introduced by Multiphase Flow Correlations on Production Analysis
Authors: Cox S. A. , Sutton R. P. , Blasingame T. A.
Published: December 2007

First and foremost, production analysis techniques require accurate rate and bottomhole pressure histories. In most cases the pressure history of the well is not measured directly at the bottomhole condition, but is calculated from surface measurements by the use of single or multiphase flow correlations. In some cases significant error is introduced through the use of these correlations.

This paper evaluates the magnitude of such errors for oil and gas producers with regard to the estimation of flow capacity, completion efficiency, and effective drainage area. Synthetic cases are used as control sets in order to evaluate the sensitivity of the results to the various multiphase flow correlations and flowing conditions. In addition to synthetic (simulated) performance behavior, field cases are presented and the variance in estimated reservoir and completion properties is evaluated.

The technical contributions of this paper are:

Systematic evaluation of the effect of errors in flow rates and bottomhole flowing pressures on production data analysis — using both synthetic and field derived well performance data. Qualitative guidelines as the effect of errors in rate and pressure on estimated reservoir properties. Establishment of the most relevant pressure drop correlations for use in practice.
Quantifying Uncertainties Associated With Reservoir Simulation Studies Using Surrogate Reservoir Models
Authors: Mohaghegh S. D.
Published: December 2007

Reservoir simulation is routinely used as a reservoir management tool. The static model that is used as the basis for simulation is the result of an integrated effort that usually includes the latest geological, geophysical and petro-physical measurements and interpretations. As such, it is inherently a model with some uncertainty. Analysis of these uncertainties and quantification of their effects on oil production and water cut using a new and efficient technique is the subject of this paper.

Typical uncertainty analysis techniques require many realizations and runs of the reservoir model. In the day and age that reservoir models are getting larger and more complicated, making hundreds or sometimes thousands of simulation runs can put considerable strain on the resources of an asset team. This paper summarizes the results of uncertainty analysis on a giant oil field in the Middle East using a new technique that incorporates a Surrogate Reservoir Model (SRM).

A Surrogate Reservoir Model that runs and provides results in real-time is developed to mimic the capabilities of a full field model that includes about one million grid blocks and takes 10 hours to run on a cluster of twelve 3.2 GHz CPUs. This Surrogate Reservoir Model is used as the objective function of a Monte Carlo Simulation to study the impact of the uncertainties associated with several parameters on the model outcome, i.e. oil production and water cut is analyzed. The analysis can be performed individually on each of the 165 horizontal wells.

During the analyses of uncertainty, the Surrogate Reservoir Model will serve as an objective function for the Monte Carlo Simulation. In this study, uncertainties associated with several reservoir parameterts and their quantitative effect on cumulative oil production and stantaneous water cut are examined.
An Information Resource for Water-Management Solutions
Authors: Hite J. R. , Shaw D. C. , Warren J. M.
Published: December 2007

Halliburton has been directing a multi-year, cross-industry initiative to develop a web-based Information Resource for Water Management Technology. It aims to help the working engineer to understand current and up-to-date Water Management principles, technologies, best practices and lessons learned. We present the philosophy and methodology employed in the analysis, design and implementation of this important industry resource.
Stressed Shale Drilling Strategy—Water Activity Design Improves Drilling Performance
Authors: Rojas J. C. , Clark D. E. , Zhang J.
Published: December 2007

Non-aqueous drilling fluids are often chosen to drill troublesome shale formations in an effort to minimize wellbore instability problems. However, Gulf of Mexico (GoM) experience has indicated that when drilling in highly faulted areas, oil- and synthetic-based fluids do not always prevent wellbore destabilization. This is evidenced by wellbore collapse, and the resulting difficulty with holecleaning, tripping, logging and casing running.

It is known that the chemical, physical, and mechanical effects resulting from the interaction between the drilling fluid and the formation may degrade the stability of the borehole in the already weakened and stressed fault interval. Commonly, the practice has been to increase the drilling fluid salt content to enhance the borehole stability. The perception that low drilling fluid water activity is beneficial to wellbore stability is one that lends itself to a needed revision.

A detailed laboratory investigation using preserved shale core and drilling information have confirmed that the water activity of drilling fluids is often much lower than necessary. This study has shown that when drilling faulted or fractured shale, the correct, not higher salt content in drilling fluids will reduce wellbore collapse problems and improve drilling performance.

A laboratory method, which allows the quantitative measurement of water and ion movement during shale/mud interactions, combined with geological information, optimizes the salinity design of drilling fluid, which controls water and ion movement. Laboratory data and field cases from GoM drilling support the concept of optimum salinity to enhance borehole stability in naturally fractured formations as part of the stressed shale drilling strategy to improve drilling performance.
Interpretation of Heat Distribution, Remaining Oil Saturation, and Steamflood Potential of Block Wa38, Liaohe Field
Authors: Gao Y. , Yang S. , Zhou Y. , Jia L. , Sun H. , Zhang Y. , Castanier L. M. , Kovscek A. R.
Published: December 2007

The Shasan formation in Block Wa38, Liaohe oilfield is a typical, massive, permeable-sandstone, heavy-oil reservoir. Dead-oil viscosity at reservoir temperature is about 12615cp and the gross formation thickness is roughly 110 m. Cyclic steam injection using vertical wells has been applied successfully for about 10 years, but is reaching the economic limit. This work quantifies the distribution of heat throughout the block and locates the remaining oil saturation using analytical and numerical models. Methods for additional recovery as well as replacement technologies are explored using reservoir simulation. The first and most significant step of this work is the interpretation of the effect of multiple cycles of steam stimulation on the remaining oil saturation. Field data, semi-analytical methods, and numerical simulation are combined to obtain realizations of the distribution of heat and oil saturation throughout a block containing 18 wells. Results show that the remaining oil is mainly distributed in the lower portion of the reservoir layer and that the reservoir volume surrounding wells is desaturated. Thus, steam override influences the sweep efficiency. The reservoir is a candidate for continuous steam injection given the distribution of remaining oil and heat within the reservoir. Numerical reservoir simulation is used to optimize the parameters in the steam-flooding process using existing vertical wells and potential horizontal well candidates. High and low quality continuous steam injection is considered. Results show that further development using steam is effective at recovering oil with decreased operational cost. At the same time, the results also show that the heat communication between the wells from cyclic steaming operations aids greatly steam flood startup.
An Eulerian-Lagrangian Formulation for Compositional Flow in Porous Media
Authors: Wang H. , Ewing R. E. , Qin G. , Lyons S. L.
Published: December 2007

We derive an Eulerian-Lagrangian formulation for two-phase, multicomponent compositional flow in porous media with sources and sinks. The formulation can be used by many Eulerian-Lagrangian methods in solving the component mass balance equations. It can be combined with different types of pressure solvers in solving the coupled systems of compositional models. A full thermodynamic flash calculation is carried out to determine phase stability and composition.

Numerical experiments are presented to investigate the performance of the formulation and to compare it with the widely used upwind method for compositional flow. These results indicate that the Eulerian-Lagrangian formulation generates stable and accurate solutions that resolve moving steep fronts and are physically reasonable, even if it uses a time step two orders of magnitude larger than that used by the upwind method.