bluuebunny/crossref_metadata_2025 huggingface dataset:
New Injection-Allocation Tool Significantly Improves the Value of Water Injection in Large Clastic Reservoirs
Authors: Mandal Dipak , Nik Ahmad Nik Nabilah Bt.
Published: December 2007

Water injection is one of the most commonly used methods for pressure maintenance in clastic and carbonate reservoirs worldwide. Monitoring this injection mechanism has remained essential to understand near term pressure response, evaluate pattern behaviour and injection potential for further expansion if required.

Increasing oil price and thus pressing business needs to produce more than earlier planned, led often to the critical situation of available injection volumes being less than that required to maintain IVRR=1. To reduce potential loss of reserves due to increased drawdown, operators around the world have tried various modes of prioritization of the limited water supply. The intention has been to maximize the value of the available injection.

To develop thus a rationalized prioritization process, a mathematical tool has been developed which calculates the individual reservoir water injection needs and then optimizes them through key ranking criteria. The criteria included voidage replacement ratio, threshold operating pressure above bubble point, conformance loss due to injection out of pay, oil response per barrel of water injected and crude quality. Unique influence functions help to assign weighting factors to each of the criteria and mathematical algorithms have been developed in Excel to allocate injection to each reservoir. This tool has been tested on a number of clastic reservoirs and a more rigorous form is currently in the process of being used in some of the waterflooded reservoirs in Peninsular Malayasia to allocate injection. It thus acts as a successful yardstick for management to ensure maximum value for injection.

This paper summarizes the process of building this allocation tool, describing the different criteria used, the generation of weighting factors from the influence functions and the mathematical algorithms that help to maximize the value of injection water.
Horizontal-Well-Production Logging Experience in Heavy-Oil Environment With Sand Screen: A Case Study From Kuwait
Authors: Oosthuizen Ricardo U. , Al-Naqi Ahmad , Al-Anzi Khalaf , Gok Ihsan Murat , Zeybek Murat , Cig Koksal , Al Hashim Hashim
Published: December 2007

Because flow regimes in highly deviated and horizontal wells are quite different from those of vertical wells, velocity and hold up distribution are required for accurate flow rate and fluid entry determinations in multiphase flow. Production logging in horizontal wells can be challenging due to undulations and completions such as sand screen.

In this paper, we present a field example that utilized advance production logging tool with distributed velocity and hold up distribution using tractor conveyance in sand screen completion. In this job, advanced production logging tool was further integrated with an additional spinner and pulse neutron tool to detect fluids in possible annulus space between screen and open hole. Results were exceptionally good measuring hold up and velocities. All the measurements showed that annulus space was filled with sand and fluid entries were determined confidently. In addition, it was shown that the single spinner in multiphase horizontal flow could not determine velocities of each phase unless totally immersed in one phase. The observations and recommendations were further discussed in this challenging production logging environment.
Missed, Bypassed, and Underestimated Hydrocarbon Traps: Analysis of BHT Records Reveals "Undiscovery Wells" in North Arabia
Authors: Ibrahim Muhammad W.
Published: December 2007

The search for hydrocarbons in Middle Eastern and North African (MENA) countries began essentially as an exploration for giant oil fields, and several exploration wells may have been suspended, plugged and abandoned and declared "dry" under giant-prone early exploration strategies, obsolete logistics, drilling technology, and production methods. Some of these "dry holes" are now proven oil producers or "undiscovery wells". Geothermal gradient anomalies associated with hydrocarbon traps have been recognised since the early days of modern hydrocarbon exploration. The goals of this study are: (1) mapping the geothermal gradients of North Arabia, (2) delineating geothermal gradient fairways and anomalies of oil and gas traps, then (3) identifying and reviewing similar anomalies in the same area as they may be indications of undrilled, under-rated or bypassed hydrocarbon traps.

In this study an exclusive computer programme was used to create BHT database, correct, test the statistical significance of BHT measurements, calculate and plot Compensated Geothermal Gradients (CGG) and Extrapolated Surface Temperature Intercepts (ESTI) of 50 exploration and development wells in the study area covering onshore Kuwait, NW Saudi Arabia, Iraq, and parts of W. Iran, E. Jordan and E. Syria (Long. 39.00 °E to 48.00 °E and Lat. 29.00 °N to 37.00 °N). The study recognised 30 Proven geothermal gradient anomalies of hydrocarbon entrapment (i.e. associated with proven oil and gas fields), and used their model to identify and delineate 3 Potential, 6 Probable and 5 Possible geothermal gradient anomalies of hydrocarbon entrapment in the area.

There are thousands of BHT data dormant in borehole records of every producing basin that can be used in similar analysis to investigate old dry holes for commercially producible traps.

Global hydrocarbon exploration history recorded many cases of early "dry holes" or "dry" anomalies becoming hydrocarbon producers at later dates. Examples are numerous; such as well K1-13 of Libya, which was classified as "dry hole" at completion date, then proved to be an oil producer at later dates is probably one of many potential "undiscovery wells" in Middle Eastern and North African (MENA) countries.
Crosswell Electromagnetic Resistivity Tomography: Pushing the Limits
Authors: Sanni M. L. , Yeh N. , Al-Afaleg N. I. , Kaabi A. O. , Ma S. M. , Levesque C. , Donadille J. M.
Published: December 2007

The cross-well electromagnetic (EM) resistivity method is emerging as one of the technologies that can be deployed for very deep reservoir surveillance/monitoring measurements. It has the potential to provide fluid distribution mapping at inter-well scale, and thus can be used for identification of bypassed hydrocarbon, monitoring of macroscopic sweep efficiency, planning infill drilling and improving effectiveness of reservoir simulation.

A cross-well EM trial is being conducted in an Upper Jurassic carbonate reservoir in Saudi Arabia to monitor the flood-front and fluid distribution with a well separation at the upper limit of the operating envelope allowed by this technology. For best results, current technology limits the maximum distance between wells to circa 1000 m for open-hole to open-hole and 300 m for cased-hole to cased-hole. Extensive pre-job forward modeling was carried out to investigate the feasibility of obtaining useful results from the measurements with such large inter-well spacing. Several scenarios of flood-front movement, such as edge water due to super-K or fracture swarms, bottom water encroachment, coning and cusping, etc., were modeled.

The modeling results were encouraging and many of the anticipated subsurface scenarios were successfully detected.
An Integrated Approach To Efficiently Unlock the Resource Potential in a Large Cluster of Fields
Authors: Kraaijveld Martin A. , Hognestad Jon B. , Samantray Ajay , Udeh Pius , Bulushi Waleed , Cerutti Andres E. , Nijman Madelon P. Y. , Al kindy Zaher , Ibrahim Ayman , Janusz Norbert
Published: December 2007

An integrated study on a cluster of 23 fields in South Oman was performed in the Petroleum Development Oman (PDO) Study Center, in order to derive a coherent view on the cluster development as well as to write (waterflood) FPDs for the individual fields. The study combined conventional and state-of-the-art workflows and was conducted by a large integrated team over a period of three years. The study was conducted in four phases: screening, full field modelling, infra-structure development and FDPs for the 6 large fields and the writing of appraisal / development plans for the remaining 17 fields. This paper describes the workflow and learnings of the study.
Preventive Treatment for Enhancing Water Removal From Gas Reservoirs by Wettability Alteration
Authors: Panga Mohan K. R. , Ismail Suzylawati , Cheneviere Pascal , Samuel Mathew
Published: December 2007

Water blocks and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trapped near the wellbore due to strong capillary forces and/or viscous fingering of gas through the liquid. To remove this liquid, alcoholic solvents are injected into the near wellbore area; however, this remedial solution needs to be reapplied in case of any subsequent water or condensate banking in the well. In this paper, we present a preventive and permanent chemical treatment for the removal of water and condensate blocks. Three types of tests have been conducted to evaluate the performance of the chemical system which include contact angle, imbibition and core flow test. A total of 41 chemicals have been tested using contact angle and imbibition tests and only 2 chemicals, A5 and A6 were selected for core flow test as they were stable at high temperature and did not damage the cores excessively during the imbibition tests. The core treated with a solution containing 5% A5 and 95% brine (2-wt% KCl) in the core flow test gave higher clean up of trapped water due to reduction in capillary force. This treatment system also shows a better alteration of the formation wettability from liquid wet to non-liquid wet conditions compared to the other chemical systems tested.
A Novel Approach of Detecting Water Influx Time in Multiz one and Multilateral Completions Using Real-Time Downhole Pressure Data
Authors: Aggrey G. H. , Davies D. R. , Skarsholt L. T.
Published: December 2007

Increasing use of advanced (intelligent) completions has provided the facility for real time reservoir monitoring through use of permanent downhole instrumentation and control of production from different zones within the reservoir through use of surface operated inflow control devices. The potential for the real-time data generated by advanced completion solutions is now being exploited to a greater extent.

The paper will demonstrate that trending analysis of the pressure drop (dP trending) using the data delivered by sensors located strategically in a multi-zone horizontal or multilateral intelligent completion can identify the time and location of water influx into a well. It will be shown that "pressure drop trend signatures" can identify the location of the water influx and application of this approach will be illustrated by use of two, three and four zone completions in synthetic reservoirs. A more complex, field based example will also be employed to illustrate the robustness of the technique. Prompt recognition of the influx of unwanted fluid and its location can be achieved using the technique described in this paper.
Recent Advances in the Understanding and Incorporation of the Multiphase Fluid Flow Properties of Fault Rocks Into Production Simulation Models
Authors: Al-Hinai Suleiman M. , Fisher Quentin J. , Grattoni Carlos A. , Harris Simon D. , Al-Busafi Bader S.
Published: December 2007

For many years it has been common practice to adjust fault transmissibility multipliers within production simulation models to achieve a history match without any scientific justification. In effect, this often means that faults are made ‘scapegoats’ to compensate for inadequacies in reservoir characterisation. In recent years it has become increasingly popular to calculate geologically-realistic transmissibility multipliers based upon measurements of absolute fault permeability and fault rock thickness. A key problem with this method is that it does not take into account the multiphase flow properties (relative permeability and capillary pressure) of fault rocks. This is hardly surprising as the multiphase flow properties of fault rocks are still largely unknown. Here we present measurements that show that under reservoir conditions cataclastic fault rocks may often have maximum gas relative permeabilities that are over two orders of magnitude lower than the undeformed reservoir sandstone adjacent to the fault. Incorporating the multiphase flow properties of faults into production simulation models is still challenging as their static and dynamic properties vary significantly compared with the undeformed reservoir. We review different existing methods for incorporating the multiphase flow properties into simulation models, and we recommend some possible approaches for treating faults that improve on the existing knowledge and software.
An Accurate Multiphase Upscaling for Flow and Transport in Heterogeneous Porous Media
Authors: Li Yan , Efendiev Yalchin , Ewing Richard E. , Qin Guan , Wu Xiao-Hui
Published: December 2007

Subgrid effects can have a strong influence on flow and transport in oil reservoirs. In this work a new model for the representation of subgrid terms is introduced and applied to two-phase reservoir flows. The model entails a construction of pseudo relative permeabilities using accurate inlet boundary conditions for the saturation field. Motivation for the form of the model is provided through a consideration of asymptotic techniques for two-phase flow. The numerical computation of the subgrid terms and the implementation of the overall method are described. The accuracy of the new subgrid representation is compared to that of coarse scale models with no subgrid treatment and to coarse models based on traditional pseudo relative permeabilities. In essentially all cases the new model provides more accurate coarse scale predictions relative to reference fine scale results. These are preliminary results.
Analyses of Wellbore Instability in Drilling Through Chemically Active Fractured Rock Formations: Nahr Umr Shale
Authors: Nguyen Vinh , Abousleiman Younane , Hoang Son
Published: December 2007

Numerous time-dependent wellbore instability problems have been reported when drilling through the chemically active Nahr Umr shale formation in the Arabian Gulf. The shale is characterized by the abundance of not only bedding planes at the macro scale but also networks of smaller natural fractures at the micro scale. The presence of fractures weakens the shale mechanically and produces higher permeability fluid flow paths within the low permeability rock formation. Because of different fluid diffusion rates, there are two distinct pore pressure fields in saturated fractured shales. Additionally, in chemically active shale formations, osmotic pressure arises due to the imbalance in mud/shale chemical activity. These facts necessitate a dual-porosity/dual-permeability approach to analytical modeling that incorporates time-dependency, fracture networks, and chemical effects on wellbore stability. However, it is difficult or almost impossible to properly characterize the necessary shale modeling parameters due to the lack of standard-size samples required by conventional testing techniques. In this paper, a comprehensive approach to simulating instability problems for drilling in fractured shale formations from an innovative laboratory characterization technique for "tiny" shale samples to field analytical modeling is presented.
Application of Thermal Recovery Processes in Heavy Oil Carbonate Reservoirs
Authors: Das Swapan
Published: December 2007

As the demand for oil grows, the petroleum industry is expanding the technology envelope to access and exploit many unconventional resources. The current focus of all major oil companies is heavy oil in highly porous and permeable sandstone reservoirs (oil sand), which presents a significant opportunity. However, viscous oil trapped in carbonates (over 1.6 trillion bbl)1, potentially a huge resource for future, needs application of new technologies to be exploited economically.

At present thermal processes like steam flooding and cyclic steam stimulation (CSS) are being used extensively for the recovery of moderately viscous heavy oil from sand stone reservoirs. Another thermal process, SAGD (steam assisted gravity drainage) is being used for the recovery of higher viscosity heavy oil and bitumen from oil sand. Some of these processes are apparently very successful with ultimate recovery over 80%.

Application of thermal processes to the carbonates poses a different challenge. In general, thermal recovery in carbonates is highly energy intensive and hence, economically challenged. Due to adverse wettability (generally mixed or oil wet), lower matrix permeability, the anticipated recovery using thermal processes is much lower compared to sand stone reservoirs. With increased access of the reservoir through horizontal wells there is a possibility that these resources can be exploited economically. A simulation study has been undertaken to explore the possibility of application of thermal processes in carbonate reservoirs. Based on the results of this work, this paper presents different possible recovery options and examines the sensitivities of reservoir parameters on thermal recovery processes like CSS and SAGD in fractured carbonate heavy oil reservoirs. The results suggest that SAGD may be viable in some of these reservoirs.
Drilling With Liner on Horizontal Oil Wells
Authors: Terrazas M. , Estrada M. , López V. M. , Jardines A. , Díaz E. , Fisher M.
Published: December 2007

This paper describes lessons learned and results obtained while applying a rotary drilling with liner system on conventional rigs, during the planning, design and drilling operation in offshore wells located in the Mexican coasts of the Gulf of Mexico.

Due that the cretacic formation named El Abra is composed by naturally fractured limestone and since its structural top (origin reef) has been eroded, it is difficult to detect it. Moreover, the differential pressure between the Tertiary and El Abra, result in several hole problems, such as: severe lost circulation, stuck pipe, cave-ins of holes and bad casing cementing jobs. These problems have increased time and cost in the drilling projects.

Continuous searching for alternative solutions with new technology to solve specific problems in the drilling process, lead PEMEX Exploration and Production to apply the non conventional option of rotary drilling with liner, meeting the safety standards established by the company.

The applied drilling with liner system, has allowed to drill down to the objective depth with high angle, cement the liner and drill out the following interval horizontally, steering in the reservoir. The system consists of a shoe drillable bit, a float collar, stabilizers, a liner with integral flush connections of high torque and a rotary liner hanger.

The results of the technique are presented utilizing a liner of 9 5/8" and a bit of 12 ¼", also hydraulic analysis, stress generated in the casing and the connections by 75° angle of hole construction, torque and drag, and drilling parameters. A comparison with conventionally drilled wells is performed, pointing out the problems found in the field, the results achieved, and how by applying the technique drilling with liner, savings of 40 days time and 5.0 MM usd per well, have been accomplished.
Development of a New Artificial-Neural-Network Model for Predicting Minimum Miscibility Pressure in Hydrocarbon Gas Injection
Authors: Birang Y. , Dinarvand N. , Shariatpanahi S. F. , Edalat M.
Published: December 2007

Miscible gas injection is one of the most effective enhanced oil recovery techniques and minimum miscibility pressure (MMP) is an important parameter in miscible gas injection processes. Exact determination of this parameter is critical to the designing of the injection equipments and the project investment prospect. The purpose of this paper is to develop a new artificial neural network (ANN) model to predict the minimum miscibility pressure of hydrocarbon gas flooding.

Different MMP correlations and models regarding the kind of injection gas and the mechanism of miscibility have been proposed, which are respectively based on mathematical and thermodynamic calculations. Almost all the correlations proposed in the literature are representative of either condensing or vaporizing mechanism or give reasonable results only in the limited range of data they are based on. In this article, by taking into consideration both condensing and vaporizing mechanisms and by using a wider range of data, the new model is introduced. Experimental data from different crude oil reservoirs carried out by slim tube test have been used to obtain a new model in which both mechanisms are included.

An Iranian oil reservoir is a candidate for miscible gas recycling with API=23 and initial pressure of 5500 psi. Sampling and recombination is done on the reservoir fluids. Flash and differential expansions are performed for fluid characterization and then miscible experiments are carried out for MMP determination with slim-tube apparatus.

The significance of this correlation is that MMP can be determined for any composition of oil and gas, no matter which mechanism is dominant in achieving miscibility. The sensitivity analysis is done and consequently the percentage of error for the model is compared with the literature data. It is shown that the results obtained from the new MMP model are more accurate when compared with other most common correlations reported.
Reservoir Candidate Screening is Critical to Ensure Successful Application of Underbalanced Drilling Technology- Case study
Authors: Babajan Salar , Qutob Hani
Published: December 2007

The Petroleum Development of Oman, PDO has been considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their fields. Among the various options available to achieve these objectives, Underbalanced Drilling technology is considered to evaluatthe benefits over traditional drilling and completion methodologies in terms of reservoir performance.

Accordingly, an Underbalanced Drilling reservoir candidate screening process was initiated to examine the suitability of the technology for seven gas reservoirs in PDO.

The screening process began by taking basic reservoir and drilling data and processing it through expert system software. The software rated the candidacy of the reservoir to help determine the likelihood of achieving success with underbalanced vs overbalanced drilling and completion techniques, to identify the best potential underbalanced candidates from the given portfolio and proceed with a detailed analysis.

The expert system score for underbalanced candidacy is calculated by considering different modules. Each module includes a comparison of the key differentiators between overbalanced and UB techniques that impact the UB candidacy of a reservoir. To make these comparisons, the expert system assumes a well is drilled overbalancedand assesses the potential effect on reservoir performance and then estimates the potential benefit of underbalanced drilled wells with minimal damage.

In this paper, the results of the screening process for the gas reservoirs examined are presented and discussed. The study confirmed that candidate selection is a critical first step before initiating any underbalanced drilling project. It also explains why when correct candidates are chosen, UBD significantly improves productivity compared with conventional overbalanced drilling practices.
Combination of Drilling With Casing and Stage Tool Cementing: A Unique Approach to Mitigating Downhole Conditions
Authors: Robinson R. , Rosenberg S. , Lirette B. , Odell A. C.
Published: December 2007

The gas fields of the western Piceance basin in northwestern Colorado present significant challenges to drilling and casing operations. This area has complex geology, with dipping formation beds that lead to "crooked hole" drilling. Fractured formations cause problems, including lost circulation while drilling, and failure to return cement to surface during primary cement jobs of the 9 5/8-in. casing. Sometimes casing cannot be run to total drilled depth.

After review of the problems, an operator in the region concluded that a different approach was warranted and selected drilling with casing (DwC) as an alternative to investigate. DwC, combined with stage cementing of the surface casing, was expected to yield a significantly more effective surface-hole drilling and casing operation, reducing nonproductive time (NPT) and the associated cost.

This paper reviews the problems encountered in conventional surface-hole drilling and casing running operations in the Piceance basin. It also reviews the operator's decisions for a DwC approach. A case history of a DwC-with-stage-tool cementing operation and its successful conclusion is presented.
World's First Annular Safety Valve for Dual Concentric Water Injection
Authors: Pearce K. A. , Skorve H. G. , Grini M.
Published: December 2007

The Hibernia field is located in the Jeanne d'Arc Basin on the Grand Banks of Newfoundland, approximately 315 km east southeast of St. John's (Fig. 1). The Hibernia Gravity Based Structure (GBS) platform has a total of 64 slots available for well construction and currently only a limited number of well slots remain. Since production began in 1997, it has become apparent more than 64 wells will be required to develop the resources adequately. As such, it was recognized a platform slot constraint issue could become a limiting factor for the timing of development of the remaining resources.

To optimize the use of the remaining slots, a unique technical solution was developed. The design concept was to drill a well through the upper Ben Nevis - Avalon (BNA) reservoir (G Block) and into the Hibernia reservoir (DD Block). This well (WIDD1/AWIG1) was the first Hibernia dual concentric water injection well. To realize this design concept, the world's first annular safety valve for dual concentric water injection was designed, manufactured, fully tested, and qualified in a fast track manner to enable injection into the annulus for the upper BNA target and through the tubing for the lower Hibernia target.

The WIDD1/AWIG1 well was successfully drilled and

completed allowing dual concentric injection as envisioned in the original well proposal. To date, one additional dual concentric injector well has been drilled and other dual concentric well concepts are actively being pursued.
Liquid Cement: Changing the Paradigm
Authors: Eid Ramy N , Mays Patrick
Published: December 2007

The process of oil well cementing has changed little since the introduction of the ground jet-mixer eighty years ago. While time has brought advancements such as; pneumatic transfer of bulk cement, introduction and application of the re-circulating mixer, liquid additives, advanced density control and additive measuring devices, the basic elements of well cementing have remained largely unchanged over time. In an offshore cementing environment the process involves the pneumatic transfer of cement or cement blended with dry products to a supply boat and the pneumatic transfer of this material to the offshore rig's storage tanks. The material is then pneumatically transferred a third time to the cement unit, where water is added and the slurry is homogenized by a large and expensive cement unit, usually coupled to a batch mixer. This tedious process occurs even on small jobs and in remote facilities.

To simplify the process, a new concept using a Liquid Cement Premix (LCP) has been developed. As its name implies, LCP is basically pre-mixed storable cement slurry that can be stored for an extended period in a homogenous fluid state and then can be used in any number of down-hole applications just like conventional cement. There are many benefits implicit in the application of this new technology. Among these are reduced environmental impact, improved quality control, reduction (or even elimination) of conventional cementing and associated equipment, elimination of cement blending and enhanced logistics for remote platforms, reduced in required personnel offshore and considerable time savings. Particularly interesting is the use of this concept for work-over and abandonment operations in situations where deployment of conventional cementing equipment would be impractical or expensive.

This paper presents the background of LCP and describes a common example of a field implementation.
New Risk-Management Standard for Delivering Superior Environmental and Safety Performance
Authors: Smith Andrew L.
Published: December 2007

Although ANSI approved ANSI / AIHA Z10-2005 – Occupational Health & Safety Management Systems in July 20051, the United States still does not have a National Risk Management Standard.

Risk management is not just something for corporations or public organisations, but for the life cycle of any E&P activity whether short or long term2. The benefits and opportunities should be viewed not just in the context of the E&P activity itself but in relation to the many and varied stakeholders who can be affected. By meeting the various component parts of this standard, our industry will not only be in compliance but can also measure itself against a new standard which represents best global practice.3

Risk management should be a continuous and developing process which runs throughout the organisation's strategy and the implementation of that strategy. It should address all the risks surrounding the organisation's E&P activities past, present and in particular, future. It must be integrated into the culture of the organisation with an effective policy and a programme led by the most senior management. It must translate the strategy into tactical and operational objectives, assigning responsibility throughout the organisation with each manager and employee responsible for the management of risk as part of their job description. It supports accountability, performance measurement and reward, thus promoting operational efficiency at all levels.

The focus of good risk management is the identification and treatment of these risks. Its objective is to add maximum sustainable value to all E&P activities of the organisation. It marshals the understanding of the potential upside and downside of all those factors which can affect the organisation. It increases the probability of success, and reduces both the probability of failure and the uncertainty of achieving the organisation's overall objectives.

Risk management is central to any organisation's strategic management. It is the process whereby organisations methodically address the risks attaching to their E&P activities with the goal of achieving sustained benefit in the form of delivering superior environmental and safety performance within each E&P activity and across the portfolio of all E&P activities.
Implementation of ROP Management Process in Qatar North Field
Authors: Remmert Stephen M. , Witt Joseph W. , Dupriest Fred E.
Published: December 2007

In March 2005, the operator implemented a rate of penetration (ROP) management process in Qatar's North Field. IPTC Paper 10706-PP describes the general principles behind the new work process and highlights its introduction to the operator. The ROP management process uses real time, customized surveillance technology to continuously maximize both drill bit cutter efficiency and transmission of energy from rig floor to the bit. This paper focuses on specific changes in drilling practices and their translation into substantive program acceleration and capital savings. To date, the development program has been accelerated by one year and USD 54 million has been saved while drilling 470,000 ft of hole. The process has proven to be a highly effective solution for management of drilling efficiency in a major development drilling campaign. As an indicator of program scope and effectiveness, over 440 personnel have been trained in mechanical specific energy (MSE) analysis, and 50 new field drilling records have been set by the nine rigs involved in the program. Importantly, the process has been implemented with one of the best safety records in industry (TRIR or total recordable incident rate of 0.11 per 200,000 man-hours as of September 06).
The Evolution of a TAML L–4 Multilateral System to Meet the Challenges of a BP Deepwater Subsea Well
Authors: Horne Ken , Allam Robbie , Glaser Mark , Chandler Peter , Scharf Thilo
Published: December 2007

The Schiehallion field lies in water depths of 1,150 to 1 475 ft and is situated west of the Shetland Islands. The reservoir was discovered in 1993 and first brought on stream in 1998. It is the largest field operated by BP in the region and is one of the largest producing fields in the UK sector. Currently there are 19 production and 19 water-injection wells in the field, which have yielded more than 250 million BOE to date.

At the outset, the North West Area Development (NWAD) of the Schiehallion field was planned to have four penetrations, consisting of two producers, each with its accompanying injector; however, design and economic reviews indicated that development with a multilateral well and matching injectors was more viable. The selected multilateral system consisted of a hollow whipstock through which perforations would be made after the completion was installed. While the perforating gun and low-side weight bias orientation system are not new technologies, they still required substantial qualification because of the unique construction of the well, driven primarily by well control policies and the requirement for an intelligent completion to facilitate independent flow control of both laterals. The resultant integration of technologies supplied by several service companies demanded rigorous testing and qualification of the various components. Several tests were performed to validate the viability of the completion design, such as perforating gun suitability; confirmation that minimal tubing deformation would occur; perforation hole sizes; the likelihood and containment of perforation debris; and testing of a straddle system required to bridge off the tubing perforations to isolate and control the mother bore production. The test program culminated in a full-scale stackup of the intelligent completion within a test well, followed by perforating and subsequent quantification of the debris generated and captured.

This paper details the development trials carried out on the perforation system required for this multilateral system to meet the needs of drilling and completing a subsea multilateral producer with an intelligent completion. In addition to discussing the physical testing, this paper summarizes the results obtained from erosion modeling and productivity evaluation, which also influenced the final well design.
Case Studies Of Emulsion Behavior At Reservoir Conditions
Authors: Kokal Sunil , Al-Dokhi Mohammed
Published: December 2007

Most emulsion studies are conducted with depressurized crude/water samples. Can emulsions form in the reservoir at high pressures and high temperatures? The answer to this question is generally anecdotal. This paper provides a unique method and new data from emulsion studies at high pressures and high temperatures. Two case studies will be presented where emulsions were suspected to be the cause of production challenges in several wells. The experiments were conducted in a special visual PVT cell with the capability of observing emulsion phase behavior at reservoir conditions. The effects of several variables on emulsion behavior were investigated including shear, pressure, temperature, watercuts, and asphaltene precipitation tendency of the crude.

The first case study is in a field that produces tight emulsions. The results of this study indicate that emulsions can form at reservoir conditions, with mixing, especially if the crude has a propensity to precipitate asphaltenes. The new data suggests that emulsion behavior is closely linked to the presence of fine solids through in-situ dynamic precipitation of organic (asphaltenes) and inorganic salts (scales) as well as fines migration in the reservoir. In the second case study, a series of emulsion tests were performed on bottomhole and wellhead samples from several wells. The results suggests that the emulsions are relatively loose at bottomhole conditions but become progressively tighter with a reduction in pressure and temperature. The tightness of the emulsions was linked to fine solids that stabilize them. These include primarily calcite and sulfur-rich heavy hydrocarbons like asphaltenes, with trace amounts of silicates (clays and/or fine grained silica), iron-rich precipitates and barite.
Magnolia Deepwater Experience—Frac-Packing Long Perforated Intervals in Unconsolidated Silt Reservoirs
Authors: Eaton Luke F. , Reinhardt W. Randall , Bennett J. Scott , Blake Kenyon , Morales Hugo
Published: December 2007

ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50°–60° maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive, fine-grained, Pleistocene-aged reservoirs.

These reservoirs require sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate, long life completions, the producing zones are frac-packed. The average perforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft.

The typical production casing string for the wells consists of 10–3/4 in. casing with an 8–1/16 in. production liner. Drift diameter through the tapered production casing is 9–1/2 in. and 6–1/2 in. respectively. The 6–1/2 in. drift diameter allows using common size screens and packers. The wells are generally completed with a 4–1/2 in. × 3–1/2 in. tapered tubing string.

Premium screens with shunt tubes are used on the wells due to the long deviated intervals. The "frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoelastic surfactant carrier fluid. Washpipe conveyed downhole pressure and temperature gauges and radioactive tracers are used to help analyze the treatment results.

This paper will discuss screen selection philosophy in silt/very fine sand reservoirs, carrier fluid selection, perforation strategy, and ability to frac across shale intervals. The paper will also cover the effectiveness of achieving a frac-pack with premium screens with shunt tubes, based upon downhole pressure, temperature, radioactive tracer information, and revised operational practices that resulted in zero to negative skin completions across long, perforated intervals that continue to produce sand free after extreme reservoir depletion.
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Authors: Colwart George , Burton Robert C. , Eaton Luke F. , Hodge Richard M. , Blake Kenyon
Published: December 2007

ConocoPhillips is developing the Magnolia field with a tension leg platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells produce primarily from thick, fine-grained, Pleistocene-age reservoirs. Due to the long lengths of the producing reservoirs and large variations in sand grain sizes/permeabilities, premium screens with shunt tubes in conjunction with cased hole frac packs have been used to complete the wells.

The third well, A1ST1BP1, was completed using the same techniques as were successfully used on the first two wells. The A1ST1BP1 completion failed during initial unloading, allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and premium sand control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was re-perforated, new screens run and a second frac-pack pumped. When laying down the washpipe after the second frac-pack, erosion marks indicated an apparent second screen failure.

A detailed examination of both A1ST1BP1 frac-pack jobs was conducted in conjunction with laboratory collapse and erosion testing of the premium screens. Collapse testing revealed the screen lost sand control at less than 1000 psi. The collapse rating stated by the manufacturer was greater than 7000 psi. The erosion tests demonstrated that inflow from supercharged reservoirs into the wellbore could erode hole(s) in the premium screen. Revised operational procedures were used in six subsequent frac-packs without any additional failures and zero to negative completion skins.

This paper will discuss the failure modes of the two frac-pack/premium screen sand failures, workover planning and execution to remove tubing with multiple control lines and fish screens with shunt tubes from close tolerance casing, as well as procedural revisions developed to successfully frac-pack the subsequent Magnolia reservoirs.
Application of a Hybrid Dual Porosity/Dual-Permeability Representation of Large-Scale Fractures to the Simulation of a Giant Carbonate Reservoir
Authors: Uba Halilu M. , Chiffoleau Yann , Pham Tony , Divry Vincent , Kaabi Abdulaziz , Thuwaini Jamil
Published: December 2007

The simulation of fluid flow in fractured reservoirs is mostly based on the Warren-Root formulation in which the matrix is dissected into blocks by fractures(1). In modern simulators, the Warren-Root formulation has been extended to account for fluid flow in the matrix as well as in the fractures(2). These two media of contrasting transmissibility and storage capacity constitute the basis of dual porosity dual permeability modeling. Hydraulic connection between the two media is managed via a transfer function. This formulation is appropriate for cases with diffuse interconnected fractures. Alternatively, fractures can be modeled explicitly by capturing their geometries, shapes and sizes in the form of numerical grid cells. But this would be prohibitively costly in terms of run time and memory.

This paper presents a method that is suitable for giant fields that are dominated by clusters of sub-vertical fractures called fracture corridors. It is based on a hybrid approach of the two alternatives mentioned. The effective Warren-Root and fracture parameters are adjusted to mimic explicit fracture modeling thereby capturing the advantages of both. The method was applied to a giant carbonate field in Saudi Arabia, which has both fracture corridors and super-permeable bodies. These bodies are typically horizontal and they inter-connect with the fracture corridors to form a combined high conductivity medium which is responsible for the unusual water movement observed in some parts of the field. The full field simulation model contains a homogeneous matrix and a fracture grid comprised of fracture corridors and super-permeable bodies. Fluid segregation is assumed in the fracture system in agreement with the physics inside conductive vertical fractures. The matrix-fracture corridor and the matrix-super permeable body exchanges are represented in a manner similar to matrix-fracture transfers in the Warren-Root dual-porosity system. Special attention was paid to matrix block size and to imbibition capillary pressure. This approach led to a reliable history match that captures the water arrival time and water production profiles in the reservoir.
Detailed Post-Event Analysis of Drilling Problems Significantly Alters the Root Cause Reality for Technical Sidetracks
Authors: Blaasmo Marit , Singelstad Arne V. , Bekkeheien Kjetil
Published: December 2007

Statoil has drilled an average of 30 technical sidetracks yearly since 2000, and a significant portion of the total drilling and well technology costs is related to these operations. A two-year project was initiated in 2004 to investigate the causes for the technical sidetracks. The project's main objective is to reduce drilling cost related to technical sidetracks.

One of the main activities in the project is the detailed post-event analyses to capture the root causes of the technical sidetracks. The analysis process includes, amongst other factors, interpretation of time based drilling and formation evaluation (FE) data. This activity was conducted throughout 2005 and is still ongoing. A total of 24 detailed analyses have been concluded with a direct cause and a corresponding root cause. The three major findings from these analyses were: Little consistency between reasons for sidetrack reported in daily drilling reports compared with root causes found from the detailed analyses.Marked reduction in formation related causes.Operational practice accounts for 10 of the 24 technical sidetrack root causes.

The majority of the technical sidetracks, according to the daily drilling report system, is due to formation related problems. However, the findings from the detailed analyses conclude that operational practice constitutes the major root cause. The picture is somewhat more differentiated, since the complex nature of some incidents results in several root causes related to both downhole mechanisms and operational practice.

These observations enforce an increased focus on the operational practice, i.e. how to conduct specific drilling operations and also how to handle drilling challenges. This paper presents why this knowledge is of great value during both planning and operations phase. Furthermore, it concludes that this type of detailed analysis significantly accelerates the learning outcome with regards to drilling operation challenges and the diagnosis of these, thus promoting a more proactive working methodology throughout the organization.
Improved Method for Use of Chelation to Free Stuck Pipe and Enhance Treatment of Lost Returns
Authors: Montgomery John K. , Keller Stuart R. , Krahel Nancy , Smith Martin V.
Published: December 2007

This paper describes how intentionally increasing the permeability of a non-aqueous fluid (NAF) filter cake can enhance treatments to free differentially stuck pipe and recover from lost returns. NAFs are well known for their ability to deposit thin, low-permeability filter cakes that reduce the risk of differential sticking. Yet, differential sticking still occurs and techniques to free the pipe have largely been ineffective. In addition, lost returns in NAF continue to be one of the industry's most difficult and expensive problems to solve.

The operator has developed an improved technique to increase the permeability of a NAF filter cake. The technique involves locally soaking the cake using a combination treatment that first conditions the cake and then removes a significant amount of the weighting material. Laboratory experiments have shown the technique can increase cake permeability by more than 850 fold.

There are at least two applications for this treatment. In the first, a pill is spotted across pipe segments (e.g., drill collars) believed to be differentially stuck. By increasing the cake permeability, pressure is allowed to penetrate the cake underneath the pipe, allowing it to more easily become free. Dissolving barite also reduces the shear strength of the filter cake, which may also facilitate freeing stuck pipe.

A second application is to enhance the performance of high fluid loss lost circulation material (LCM) treatments after NAF has damaged the fracture face permeability. Increased permeability enhances loss of the LCM carrier fluid and development of the immobile mass required to stop the growth of the fracture induced during lost returns. Formation integrity can then be rebuilt using rock mechanics-based techniques.