bluuebunny/crossref_metadata_2025 huggingface dataset:
The Injection of Multifunctional Chemicals via Gas Lift Increases Oil Production
Authors: Jackson Mike
Published: December 2007

Gas lift production is well known for its sensitivity to high viscosity fluids that can be produced when oil and water form emulsions downhole. Gas lifting can produce emulsions which are stabilized with naturally occurring components such as asphaltenes, paraffins, inorganic scales and sands. These factors; sensitivity to high viscosity fluids and the potential for the generation of emulsions, makes gas lifted wells ideal candidates for the injection of friction reducers. Friction reducers can also be formulated with different chemical additives to address other potential problems, such as scale, corrosion, hydrogen sulfide and hydrates. The injection of a single chemical product containing a mixture of different types of additives is known as a multifunctional product. The injection of one single multifunctional product into the gas lift gas can solve the logistical issues of multiple tanks, multiple injection pumps while solving problems downhole and in the flow line.

This paper will concentrate on the development and application of multifunctional products that contain friction reducers as the primary additive. This paper reviews the conditions that can cause downhole emulsions, the laboratory techniques used in the product selection and the laboratory procedures to investigate compatibility issues. Case histories of successful applications off-shore Brazil.
Multi Type Application of Cement-Packer: Simple and Economic Method of Accessing By-Passed Reservoir Potential
Authors: Idris Muhammad , Rylance Martin , Joenoes Krisjahbana , Firmansyah Nanang , Supriyono Anton
Published: December 2007

Over a significant time-period, during the development of a field; a number of factors will contribute to an increased understanding and appreciation of the identification of pay, it's distribution and potential. As a result, it is not unusual to find that a significant number of opportunities may exist within existing well-stock; but that these opportunities are ‘isolated’ by limitations of the original completion design. Accessing these reserves then simply becomes a question of completion ‘adaptability’, optimization and economics. Therefore this paper describes the application of a rig-less ‘cement-packer’ approach, in order to economically access these reserves, while retaining the necessary level of completion integrity. The paper describes the steps involved in achieving this, from concept, through planning to execution. Finally, a number of case-studies (with variants) are presented to demonstrate the increasing development and applicability of the process.

Within VICO Operations, the cement-packer process was first introduced in 1995, since then a number of variants of the approach have been developed and applied. These variants have been driven in response to individual well limitations, special requirements and also with increased technical understanding and experience. These continuous improvements have meant, that since 1995, more than 70 wells have now been remediated using this approach.

Historically, the cement-packer operational approach has been extremely efficient and has enjoyed a high mechanical success rate. In addition to this, the majority of these treatments have been performed on idle well stock; with over 50 idle-wells having been returned to production. In terms of their success, the cement-packer treatments have delivered at economic rates to VICO, where conventional work-over operations would not have been a viable option.

It is likely that an operator would consider that such by-passed opportunities would generally require a costly, lengthy and complex work-over operation; and potentially discard the option due to the economics and risks. However, this paper clearly demonstrates that the cement-packer approach is a simple, efficient and economic method of accessing such bypassed pay, while helping ensure acceptable well-bore integrity is retained.
Thermal Signature of Free-Phase CO2 in Porous Rocks: Detectability of CO2 by Temperature Logging
Authors: Hurter S. , Garnett A. , Bielinski A. , Kopp A.
Published: December 2007

This study examines the suitability of thermal methods, especially DTS (Distributed Temperature Sensing) cables (in the annulus or behind casing) to monitor the fate of injected CO2 for emissions reduction purposes. The static temperature signal of CO2 stored in pores of sandstone and claystone examples is calculated as a function of porosity, CO2 saturation, and CO2-filled reservoir thickness. The dynamic temperature signal associated with the movement of CO2 in the well and the porous rock is discussed and results of numerical simulations are presented. The detectability of these temperature signals is assessed and found to be useful in detecting leakage over short time intervals and saturation changes in the storage reservoir over the longer term.
Qualification of CO2-Capture Technology
Authors: Helle Kaare , Myhrvold Tore , Bratfos Hans
Published: December 2007

The present document describes a systematic procedure for the qualification of CO2 capture technology based on DNV-RP-A203 "Qualification Procedures for New Technology".

The procedure explains in detail how to identify, describe, and manage risks (failure modes or threats) with the implementation of new CO2 capture technology in a quantitative way by following a set of sequential steps known as the qualification process.
A Scarce Resource
Authors: Tyler Seth , Cornwell Kevin
Published: December 2007

The lack of availability of required skills and experience in most if not all parts of the oil and gas value chain is well documented so, rather than trying to make the case, we will summarise the challenge thus: the industry in all parts of the world can't find the capability it needs to safely get its work done in the timeframes it would like.

However or wherever the situation is measured, the consequence is that in days when the oil price might suggest that the industry has "never had it so good", many companies are falling seriously short of stakeholder expectations with projects of all types not being completed as planned or failing to deliver anticipated returns.

Close to home we see producers consistently missing quarterly production targets and a seemingly constant downgrading of forecasts and year-on-year plans. This leads to a constant stream of bad news and criticism in the media, greater stress through all levels of management and an inevitable "knee jerk" towards a more short term focus.
Unique Methodology for Well Re-entries Requiring Sand Control Improves Production Potential
Authors: Penno Andrew , Fitzpatrick Harvey , Garrison Greg
Published: December 2007

In re-entry or workover type situations, the primary performance objectives determined during the initial well completion remain the same, especially in deepwater, high-rate wells. These generally require running the largest-diameter casing string possible, since the dimensions of the completion equipment can determine critical well objectives. Especially in reservoirs requiring sand-control reliability, production rate becomes a primary concern in the workover situation. Issues regarding critical erosional velocities, reservoir sweep or recovery efficiency and feasibility of installing flow controls or intelligent-well equipment remain.

For mature wells requiring a side-track, the current well-construction practices necessitate reduced dimensions of the sand-control completion-equipment. This paper presents a well construction/completion methodology that supports increased completion-component dimensions in side-tracked or new wells, potentially improving overall well performance. The system is suitable for any openhole gravel-pack completion.
BP Norway: Zonal Isolation in Openhole Chalk Formation
Authors: Jorgensen T. , Anderssen S. , Skjerven T. , Vadset K. , Angell P.
Published: December 2007

The Valhall field has been producing oil for 25 years. The completion strategy of the field has continuously been developed over the years, with cased hole completions with multiple propped fractures as main completion strategy since the mid 1990s. This completion technique was also chosen for the Valhall Flank Project initiated in 2001. The later stages of the project several of the well targets were located on the borders of the field, where the reservoir formation is considerably thinner and has a lower porosity and higher reservoir pressure than in the centre of the field. Using multiple propped fracture completion technique for these targets was not regarded attractive, and to access the reserves in these targets in a cost effective manner it was decided that the optimal design for the "thin pay" targets was a concept with pre-perforated liner in open hole.

This paper describes the completion design evolution on Valhall and the considerations made for choice of completion method for the later stages of the Valhall Flank Project. An overview of the swell packer technology, in addition to the specific packer design for Valhall, is given and it is discussed how this technology provided opportunities to isolate several parts of the well if excessive water production occurred. Future applications for swell packer technology are also discussed.
Continuous Downhole Fluid Log Powered by an Integrated Approach Reveals Reservoir Fluid Complexities and Minimizes Uncertainties
Authors: Okuyig Moyosore , Berrim Ahmed , Xian ChengGang , Haddad Sammy
Published: December 2007

Fluid characterization quantifies the reservoir phase behavior, fluid compositional changes throughout the reservoir, and changes in fluid properties as a result of production and injection processes. High-quality fluid data are critical for reliable modeling, reservoir-engineering calculations, and performance predictions and for subsequent economic analysis. Compartmentalization and spatial variations of fluid composition are two primary factors that cause major and expensive differences between predicted and actual performance in the oil field. Furthermore, different depletion/development levels, and injection and production processes of different reservoir zones or compartments not only motivate more variations of fluid properties, also trigger contacts migration and unexpected injection fluids channeling or breakthrough. A large number of Downhole Fluid Analysis (DFA) stations coupled with several DFA directed sampling stations throughout all interested zones, toward a ‘Continuous Downhole Fluid Log’, is essential to reveal fluid complexities effectively and efficiently.

In this paper, we highlight a successful ‘continuous downhole fluid log’ case to address complexities of reservoir fluids in a complex carbonate reservoir. The ‘continuous downhole fluid Log’ provided significant clues and answers to a broad range of reservoir issues including compartmentalization, fluid compositional variation, unexpected identification of oil, oil reserve assessment, and gas compositional analysis to understand its origin and potential contact migration. We stress the need for an integrated and a multidisciplinary approach to fluid characterization to increase data acquisition efficiency and minimize measurement uncertainty. The approach has integrated drilling fluid optimization, new technology utilization, operation best practices, and real-time quality control and decision making. Such an approach ensured reliable rock and fluid data, thus minimizing technical risks and maximizing the economic value of the hydrocarbon assets.
Alternatives to Traditional Reinjection Methods
Authors: Bassett L.
Published: December 2007

SPE Eastern Regional Meeting-Lexington, Kentucky
The Application of NMR Logs for the Evaluation of Gas Reservoirs with Low Salinity Formation Waters
Authors: Claverie M. , Maggs D. , Van Steene M. , Westacott D.
Published: December 2007

The analysis of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones, and high apparent clay content. Calculated water saturations are high, and need to be accurately split between clay-bound, capillary-bound and free water. In addition to these reservoir characterization problems, we observe effects caused by the drilling process, such as gas dissolution in OBM filtrate, and time-lapse effects between LWD and Wireline logs.

NMR measurements of porosity, bound fluid volume, pore size distribution, and direct fluid identification can be applied to resolve the challenges mentioned above.

We demonstrate the use of NMR data to calculate total and effective porosity, and volume of irreducible water in productive reservoir sands and in shales, to validate the petrophysical model. We also present a method based on NMR analysis to estimate net producible pay and its uncertainty.

We apply fluid typing from NMR Relaxation and Diffusion maps to quantify small volumes of gas present in the water zone. This analysis enables us to calculate the fluids composition in the invaded zone and to improve the accuracy of density porosity, even when LWD and Wireline logs are combined. We also show how the NMR measurement of gas volume in the invaded zone can be correlated to sonic measurements for quantitative fluid substitution.

We identify gas in thin and shaly reservoirs from NMR stand-alone fluid typing, and present examples of successful sampling with wireline tester in these elusive reservoirs.

The various examples presented in this paper describe practical petrophysical methods used to improve the formation evaluation of shaly gas reservoirs in fresh formation water, and demonstrate how the NMR data can be integrated into an existing petrophysical analysis, improving the accuracy of results in this challenging environment.
A Standard Real-Time Information Architecture for Drilling and Completions
Authors: Pickering J. G. , Whiteley N. , Roye J. , Turnbull H. , Cavanagh D.
Published: December 2007

BP is looking to implement a standard data architecture for real-time drilling & completions information. This will enable us to make wider use of our collaboration centres through a common approach and will allow us to leverage the developing WITSML standard more effectively in our operations.

BP uses many different service organisations to deliver its global drilling & completions agenda. In the past, this has resulted in a lack of standardisation in real-time information flow. We have been unable to share data and expertise readily between different operating centres. Applying a common approach to information access on a global basis will enable us to streamline our operations and make wider use of emerging collaboration technologies.

WITSML is now finding greater uptake in our industry and we are seeing new compliant intelligent software tools emerging from different vendors. These will undoubtedly enable us to drill and complete smarter but we need a standard information infrastructure to deploy them widely and consistently. It is these smart tools that will ultimately deliver real value to oil companies.

The adoption of a standard D&C information architecture may seem an obvious step but there are very few oil companies that can claim to have delivered it. WITSML is the vehicle to allow this to happen and over the next few years it is likely that there will be much more emphasis on open connectivity between different vendors and services supporting the drilling & completions functions.
Fluid Loss Pills Control Losses through Sand Control Screens without Damage or Cleanup
Authors: Lamb Keith F. , Ali Syed A. , Harper Brian F. , Darring Michael T. , Marine Hope C. , Foxenberg William E.
Published: December 2007

This paper describes workover and completion operations offshore Trinidad & Tobago and the Gulf of Mexico in which the operator desired non-mechanical isolation of the reservoir section above the sand-control assembly. Each well required clear brine of kill-weight density and in the case of the five dry gas wells described, losses of significant volume of brine to the formation was unacceptable. Isolation of the reservoir was required for up to 18 days. The following objectives were specified: Reduce fluid losses to the formation from inside the sand control screen,Minimize the potential for formation or screen damage, andEliminate post-job, clean-up treatment of any kind.

This paper describes the development of specially formulated fluid-loss control pills and their subsequent use in the field to provide reservoir isolation by placing a temporary filter cake on the inside surface of the sand control screen. The paper describes laboratory tests designed to optimize the pill formulation to seal the inside surface of each specific screen, minimize spurt loss, maintain rheological properties for an extended period at reservoir condition and, importantly, displace off the screen with gas production. In each of the cases described, field spotting procedures were designed to eliminate killing the wells by bullheading, thus significantly reducing the volume of fluid lost to the reservoir. The authors provide details of the properties of the pill and the field procedures used to place the pills in the wells. All wells were returned to production without any remedial treatment whatsoever or impact on productivity. Additionally, the savings in time, costs and lessons learned associated with these projects and recommendations for similar future projects are discussed.
Solid Expandable Tubulars Deliver on Promise and Potential
Authors: Holland Mark , Jennings Iain , Kaschke Markus
Published: December 2007

With over 750 installations worldwide, solid expandable tubular systems have gone from an evolutionary idea to a technology that delivers on its promise. Long touted as a technology that can help operators mitigate downhole challenges, expandable tubulars are now being applied as enabling systems in wellbore construction, in field development, for casing repair and remediation and for field-wide revitalization.

The installation records for these systems are as wide as the application realm and exemplify the adaptable nature of the technology. This adaptability has led to the technology evolving from being used strictly as a drilling-problem solution to an integral wellbore component. Solid expandable systems have been used in a variety of environments, such as HTHP and ultra-deepwater projects, and for a myriad of conditions such as control of lost circulation zones, casing shoe extensions and isolation of unstable formations. In cased-hole situations, these systems have been used to isolate old perforated intervals or protect weak casing, replacing less reliable conventional squeeze cementing techniques. Solid expandable systems have helped operators reach and produce reserves that previously were unattainable due to drilling conditions and economic constraints, have provided flexibility for exploration-well uncertainties, and have reduced well costs with a slimmer well design.

Case histories will demonstrate how solid expandable tubulars have delivered on the promise and potential as an enabling technology. Case histories to be included will describe how solid expandable systems have been successfully incorporated in a field-development project in Malaysia, a casing-repair project in China and as a vital component in a total drilling-management project in the Arabian Sea. This paper will also validate the economic viability of these systems as a contributive and reliable technology.
Fast Shut-in Tools Improve Near Wellbore Characterisation from Build-up Test Interpretation
Authors: Guerrero Rodolfo Phillips , Lessi Jacques
Published: December 2007

The wellbore storage effect has been extensively studied during the last 40 years, highlighting its effects on the early time build-up data and on the resulting hurdles or mismatching tendency during the interpretation process. Although these phenomena, mainly due to the compressibility of the fluids1, can be reduced using a down-hole shut-in tool, they are not completely eliminated and most of the information related to the near wellbore area remains inaccessible. However, it appears that the interpretation inaccuracy is greatly influenced by how fast the production is shut down before the build-up test. An instantaneous down-hole shut-in action reduces the masking effect due to the wellbore storage. Therefore, during the build-up early time, it will provide more valuable data, useful for an accurate characterisation of the near wellbore region and its heterogeneities.

The following paper shows the effects of the shut-in time on the data acquisition at early time and its interpretation. Simulations have been performed in typical well configurations and reservoir types (near wellbore permeability reduction, fractured well, layered reservoir). The results illustrate clearly the benefits of an instantaneous production shut-in action to characterise near wellbore reservoir. Oilfield data have been acquired during an oil well test using a fast shut-in tool which allows shutting down the production within 2 seconds. A slight deflection in pressure build-up can be observed in the first minutes. This deflection has been interpreted as a reduction of the fluid mobility close to the well. Numerical simulations performed using the resulting model matched on this data set, demonstrate that the mobility reduction could not have been detected using a slow action shut-in tool.
Application of Pressure Derivative Function for Well Test Analysis of Triple Porosity Naturally Fractured Reservoirs
Authors: Mirshekari B. , Modarress H. , Hamzehnataj Z. , Momennasab E.
Published: December 2007

This paper concentrates on pressure transient tests in triple porosity naturally reservoirs (NFR) with pseudo steady state flow regime using direct synthesis technique.

The direct synthesis technique couples the characteristic points and lines from a log-log plot of pressure and pressure derivative data resulting in simple equations to solve for the desired reservoir parameters. Parametric analysis in dimensionless space illustrates the behavior desired reservoir parameters and provides the basis for newly empirical correlations relating these parameters to the field data. Applicability of the empirical correlations corresponding to the characteristic points developed as a result of this work is demonstrated by successfully analyzing simulated pressure transient tests. The direct synthesis method is proposed to overcome problems for the case where there is no guarantee on existence of an early-time unit slope line and/or the latetime infinite acting radial flow line has not been seen due to inner and outer boundaries, lack of points and severe noise problem. Both the effect of wellbore storage and skin are included in the analysis. As a result of this work, direct synthesis simplifies evaluation of pressure transient tests in triple porosity naturally fractured reservoirs (NFR) with pseudo steady state flow regime, eliminates the type curve matching or regression analysis. Before this paper, only one paper was published for well test analysis of triple porosity naturally fractured reservoirs with unsteady state behavior using direct synthesis technique. But in that paper, the effect of wellbore storage and skin in the analysis was not considered and also several interrelated constants were included in the equations used for estimating the reservoir parameters which makes the estimation complicated and erroneous.
A New Method to Evaluate Leak-Off Tests in Shallow Marine Sediments (SMS)
Authors: Paknejad Amir , Schubert Jerome , Amani Mahmood
Published: December 2007

Leak-off Tests (LOT) and Pressure Integrity Tests (PIT), are verification methods to evaluate cement jobs and estimate the formation fracture pressure at the casing shoe.

Although analysis of LOT in deep wells is considered a well known and practical procedure, the interpretation of LOT in Shallow Marine Sediments (SMS) is less clear. LOT in SMS gives a non-linear relationship between the pumped volume and the observed pump pressure and there is no obvious point of deflection or "leak off’ from the initial linear section of the plot. Because of non-linearity of LOT plots in SMS, LOT could be inconclusive and difficult to interpret. Incorrect interpretation of LOT would lead to costly problems that might jeopardize well progress such as; unnecessary squeeze jobs, premature setting of casing, and lost circulation problems.

This paper presents a new method to analyze casing shoe leak-off pressure in the SMS. A mathematical model is derived to assist in analyzing non-linear LOT behavior and the new method is supported by field data from LOT in SMS.

LOT interpretation is the basis for the critical drilling decisions such as; casing setting depths, cement job evaluation, drilling fluid selections, and well control methods. Correct interpretation of the LOT can help to avoid variety of problems and save considerable amount of time and money.
Study on the Pilot Test with Microbial Profile Modification after Polymer Flooding in Daqing Oil Field
Authors: Jun Sui , Fenglan Wang , Zhiyao Wang , Yanqing Bian , Zhenyu Yang , Menghua Guo , Wei Li , Zhaowei Hou
Published: December 2007

In order to further enhance oil recovery of the reservoirs, after polymer flooding, two strains of bacterium that could be used on microbial profile modification have been screened. The bacteria are separated from the fluid sample produced within the commercial polymer flooding blocks of Daqing oil-field, and named DT-1 and DT-2. The evaluation of performance shows that these two microorganisms could not only adapt to the special conditions of the reservoirs after polymer flooding, but also could grow well with the in-situ microorganisms. The results of physical simulation core flooding proved that injection profile modification bacteria play a good part in plugging after polymer flooding (the rate of plugging is more than 70%) and oil recovery could be improved about 3.9%(OOIP). In order to demonstrate the technique might as well be feasible, for the first time, after Daqing oilfield polymer is flooding, the test area carries through microbe injection pilot tracey in the world wide. The test data of two adjustment wells interpret that the permeability rate of north2 -fourth 5-p16 well falls to 45.18%, the second half year's adjustment of permeability rate is measured 393.7×10−3μm2, that is compared with the former adjustment still falling to 34.54%. At the same time, injection pressure of 2-fourth 5-p16 well by injection profile modification preceding 8.0mpa comes up to 9.4MPa, rising clearly 1.4MPa; the injection pressure of north 2-4 -p26 well rises 0.8MPa. The six environmental production wells are compared with the former adjustment, containing water decreases 3.9%, the daily production oil ekes 16t, the accumulative amount of oil totally increases 1300t. After microbial treatment, injection profile has been changed greatly, which some of the old taking-fluid zones disappear or others taking more of the fluid become taking less of that and several new zones are taking water. As a result, water cut has decreased and oil production has increased. This study has provided a good method for enhancing oil recovery after polymer flooding.
Using Geomechanics to Optimize Field Development Strategy of Deep Gas Reservoirs in Saudi Arabia
Authors: Ahmed Mahbub S. , Finkbeiner Thomas , Kannan Adnan A.
Published: December 2007

Saudi Aramco has embarked on drilling long horizontals and maximum reservoir contact (MRC) wells in the deep gas reservoirs. Regional stress field is playing an important role in predicting wellbore stability and future production performance of these wells. To successfully drill and produce these long horizontal wells a detailed geomechanics study and its results needed to be incorporated in the decision tree. Reservoir Management was keen to find the optimum azimuthal direction to place horizontal wells, which will minimize the risk of hole breakouts, optimize drilling mud weights, and ensure sustainable production under depletion mode. A study was undertaken to study the effect of geomechanics on drilling and production of these gas wells. Drilling and production histories along with laboratory measurements were incorporated in the study. The study concluded that horizontal wells should be drilled parallel to the locally derived maximum principal stress (SHmax) azimuth to maximize borehole stability and minimize required mud weights during drilling and production. To date a substantial number of wells have been drilled in the field following the recommended drilling direction that would ensure minimum damage to the reservoir and well's productivity.

The objective of the paper is to illustrate methodologies employed to find the optimum drilling direction causing the least damage to the reservoir and discuss implementation of its findings in the field development.
Successful Water Shut-off in Open Hole Horizontal Well Using Inflatables
Authors: Al-Shahrani Faisal F. , Baluch Zulfiqar A. , Al-Otaibi Nashi M. , Sarfraz Tashfeen
Published: December 2007

Water shut-off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8" open hole at 10,600 ft at 88 ° and capping it with cement and gel using coiled tubing (CT).

Historically, it has been difficult, if not possible, to perform mechanical water shut-off in open horizontal well, as inflatables are quite sensitive to be set in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to apply similar techniques to liven dead horizontal wells in other fields.
Laboratory Studies of MEOR in Micromodel as a Fractured System
Authors: Nourani M. , Panahi H. , Biria D. , Azad R. Roosta , Haghighi M. , Mohebbi A.
Published: December 2007

Microbial enhanced oil recovery (MEOR) is receiving renewed interest worldwide in recent years as a viable method while not damaging the reservoir is proven to be remarkably effective, however to some extent costly. This method is based on microorganisms’ activities to reduce residual oil of reservoirs, which is dependent on behavior of inherent microorganisms or injection of bioproduct of external microorganisms.

In this work, five bacterial species were taken from MIS crude oil that is one of the aging Persian fractured reservoirs. These microorganisms are substantially strong in increasing oil recovery especially by reducing IFT and other MEOR mechanisms such as change of wettability of rock at the favorable condition for the activities of these bacteria observed within the temperature range of 50°C to 90°C at the atmospheric pressure.

Two series of visualization experiments were carried out to examine the behavior of microbial enhanced oil recovery in micromodels designed to resemble the fractured system: static and dynamic. In the static one, carbonate rock-glass micromodel is used to simulate the reservoir conditions and the latter is performed by a glass micromodel which has a fracture with 45 degree inclination. The image processing methodology is used to determine the recovery achieved by MEOR in the micromodel made of glass.
Lithofacies, Sand-Bodies Geometry and Depositional Setting of the Datta Formation in Surghar Range, North Pakistan
Authors: Obaid Shams , Qureshi Amjad W. , Abbasi Iftikhar A.
Published: December 2007

Thick Mesozoic sedimentary racks are exposed overa wide area in the Lower and Upper Indus Basin of Pakistan, particularly along the western margin of the Indian Plate. The Mesozoic sequence is generally comprised of clastic facies in the lower part, carbonate facies dominate in the upper part. In the Surghar Range the Datta Formation represents the lower part of the early Jurassic sequence. The formation is comprised dominantly of clastic facies with carbonate interbeds at places. The Datta Formation of early Jurassic was measured and described in the Chichali and Pannu gorge, Surghar Range. The total thickness of Datta sediments at Chichali section is 161m while thickness of the Pannu section is 225m. Sections were measured for sedimentological studies and sand bodies were classified accordingly. On the basis of lithological variation and sedimentary structures eight lithofacies have been recognized. These lithofacies are; LF 8: Clay lithofacies, LF 7: Cross bedded sandstone lithofacies, LF 6: Siltstone lithofacies, LF 5: Interbedded limestone and shale lithofacies, LF 4: Sandstone with intercalations of clay lithofacies, LF 3: Carbonaceous shale lithofacies, LF 2: Channelized sandstone lithofacies, LF 1: Interbedded sandstone and shale lithofacies.

Three kinds of sand bodies were identified, these are mostly multistorey channels but some simple ribbons as well as sheets are also present. Fossils identified are gastropods and pelecypodes.

After collecting and interpreting the data acquired from the measured sections and sandstone bodies' geometry analysis, it is interpreted that the Datta Formation was deposited along the delta plain and delta front setting by a fluvial-wave dominated delta. Continental, transitional to oceanic conditions prevailed at the time of deposition of the Datta Formation and all the facies show prograding deltaic setting. Cross beds interpretation indicates east to west flowing channels.
Addressing Some of the Unique Challenges of Drillstem Tests in Tight Gas Reservoirs
Authors: Akram Agha Hassan , Khan Mohammed Riaz
Published: December 2007

An innovation in the methodology of conducting drillstem tests (DSTs) in tight gas reservoirs is presented, along with a simplification in the interpretation of the data obtained. DSTs in tight gas reservoirs are a problem because the flow rates are often too low to be measured by conventional equipment. In these cases a normal flowing and buildup test should be followed by a closed chamber test to produce usable estimates of flow rates at various times during the preceding normal flowing and buildup test. This estimated flow rate can then be used to interpret the buildup after the flow testing, which is produced by shutting the downhole valve.

In the interpretation of DST data from a tight gas reservoir, factors such as the following have to be considered: 1) large variation of gas properties resulting from the large pressure range involved1,2; 2) flow rate duration that can be many times shorter than the buildup period3,4,5,6; 3) varying flow rate during the flowing part of the test; and 4) impact of boundaries and heterogeneities.

We show that a simple interpretation approach with constant flow rates and pseudo-pressure yields results that are within the intrinsic accuracy limits expected from such a test.

The benefits to the field interpreter of using the methods presented are 1) operational flexibility: if the well flows strongly enough the rate may be measured at surface; if it does not, a closed chamber test can be added; 2) the benefit of the deeper radius of investigation of a test flowing at surface is retained; 3) field interpretation is simpler whether surface measurement is possible or not.
Fracture Characterization and Their Impact on the Field Development
Authors: Jadoon M. Saeed K. , Jadoon Ishtiaq A. K. , Bhatti Abid Husaain , Ali Asghar
Published: December 2007

Fracture characterization is a biggest challenge for the geoscientists in sandstone and carbonate reservoirs. With the advancement of all technical capabilities in the acquisition of surface and subsurface Geological data, still it is extremely difficult to understand, characterize, and predict the distribution of fractures in a field. Image logs can successfully be used to locate and to provide directional trends of fractures near the wellbore. However, capturing all the fractures in one well and to predict their flow behavior can still be a challenge. In this paper, a case study of a fractured carbonate reservoir will be presented. The field is currently producing about 500 bbl of oil per day through fractures. Four wells have been drilled on the structure to drain the oil reserves. Water flooding is being carried-out in the field for the last 9 years for pressure maintenance and now 80 % water is being produced. The reservoir has very low primary porosity and permeability, and the flow is through fractures only. On the basis of the three wells fracture data, a new well was drilled, located ideally at a structurally higher position, in crestal area of the field. Image data showed abundance of fractures with different orientation was seen in the well bore but the well didn't flow and that led to its suspension. In this study, fracture data from image logs is compared with outcrop analogs and seismic reflection and interpretation data. In this paper, limitation of the available information, importance of understanding the stress regime, integration of G & G data and lesson learned from the current evaluation of the fracture system and their impact on development of field in Potwar basin will be presented.
A Novel Method to Calculate the Reservoir Pressure of Tight Sand Using the Hydraulic Fracturing Information in the Denver-Julesburg Basin
Authors: Yang Yuanhai , O'Connell Wally , Birmingham Thomas , Hu Guonong
Published: December 2007

Based on the relationship between formation pressure and minimum horizontal stress, as well as the low leak-off rate and abnormal high reservoir pressure commonly observed in tight sand, the authors devised a new method to calculate the reservoir pressure in tight sand using the pre-frac test. Numerous methods have been published to calculate reservoir pressure using pre-frac test. However, all of them require extended pre-frac testing time, taking hours in conventional formation while days in tight sand. It is not practically viable to keep the frac crew waiting so long before a frac can be executed. In contrast, this new method uses the information collected from a 5-minute pre-frac test, which is standard routine for fracs in the Denver-Julesburg basin (DJ basin). Furthermore, this new method has been validated by the conventional well tests conducted by several service companies.
Numerical Simulation and Experimental Studies of Oil Recovery via First-Contact Miscible Water Alternating Gas Injection within Shaley Porous Media
Authors: Al-Mamari F. A. , Al-Shuraiqi H. S. , Al-Wahaibi Y. M.
Published: December 2007

Most clastic reservoirs contain discontinuous shales that act as barriers or baffles to fluid flow and can not be correlated between wells. To our knowledge, there are no published studies on the effect of discontinuous shales on First Contact Miscible Water Alternating Gas (FCMWAG) processes and how they might alter the sweep efficiency. This work aims to remedy this deficiency.

A series of well-characterized laboratory experiments in two-dimensional homogeneous and heterogeneous beadpacks were carried out. Both simultaneous and slug FCMWAG displacement experiments were performed in the porous media containing discontinuous shale. Simultaneous injection was conducted at WAG ratios of 1:1, 4:1 and 1:4. Slug flooding were carried out at a WAG ratio of 1:1 with slug sizes of 5% PV and 50% PV. All experiments were then modelled using IMPES finite difference simulator without using history matching (all simulations used directly measured porous media properties as inputs) to quantify the accuracy of the simulation when modelling the FCMWAG displacements in a porous media with a discontinuous shale.

For simultaneous injection, experiments and simulations have demonstrated that there is an optimal WAG ratio, at which oil recovery is maximized. Additionally, the simulator predicted fairly the location of the bypassed oil which was mainly downstream of the shale unit. However, a poor match was found between measured and predicted water and solvent cuts because in the simulation it is assumed that the injected water and gas flow simultaneously whereas the experiments show that:

solvent and water prefer to flow in segregated paths rather than flowing simultaneously across the whole porous media, and due to the segregate flow, water laterally blocks solvent from contacting the bypassed oil which reduces FCMWAG efficiency.

In slug injection, the large water slug (50% PV) displacement outperformed the 5% PV slug process because the large water slug injected ahead of solvent significantly reduced the extent of fingering and the bypassed oil around the shale barrier. Simulation of the slug WAG experiments showed good agreement for the oil recovery. However, a discrepancy in the physics of the fluid flow during the displacements especially downstream and upstream of the shale barrier was observed in the fluid cut curves. Simulation predicted less fingering and fewer breakdowns of the injected slugs.
Offshore Gas Field Development Optimization Study Applied QA/QC Procedure for Models Accuracy and Decision Reliability "Full Field Compositional Simulation Study—Case History"
Authors: Salameh Lutfi A. , Al Jenaibi Faisal
Published: December 2007

This paper is discussing the main challenges that are still encountered after constructing simulation models incase of not introduced to a practical QA/QC procedure to ensure accurate results for reservoir management decisions.

The study includes the main criteria's which were used to define the optimum development plan for gas production improvement towards achieving maximum recovery.

The field was partially developed in 1989 with 10 gas producers to supply 500 MMscf/day of gas for auto injection into oil rim reservoir. The field is under further development scheme to produce 1.0 Bscf/day to meet the increasing demand of gas for auto injection into other oil reservoirs and for export.

The main difficulties encountered to develop this field are linked to obtain representative model, in addition to other related development aspects of drilling costly gas wells and utilization of the produced gas for auto-gas injection or export.

Several methods (Deterministic and Stochastic) have been introduced to distribute hydrocarbon in the geological model, which was compared later with simulation model estimated initial gas and condensate in-places to ensure achieving more reliable volumes. The current and the future development plans' performances were assessed using detailed compositional simulation model that was constructed based recent rock and fluid characterization studies.

The newly established QA/QC procedure for model's results accuracy has been successfully applied, and the lessons learnt were shared with other simulation teams.

The study main outlines are as follows:

Achieve reliable history match with field data that showed discrepancies. Apply new QA/QC for accurate modeling results and assurance to resolve the common outstanding issues. Develop representative hydraulic lift curves. Develop representative equation-of-state (EOS) for fluid characterization. Optimize the current and alternative development plans.

The results and conclusions of the study are as follows:

– Anomalies screened and defined accurate estimation method for the initial gas and condensate asset volumes. – Correction factor applied to phi-log derived data in order to honor the core derived data. – Developed representative equation-of-state (EOS) and the hydraulic lift curves (HLC). – Constructed reliable full field compositional simulation model matching the field measured data. – New QA/QC procedure has been established to resolve the common outstanding issues. – Evaluation of the current and other alternative development options. – Evaluated the key parameters required to define the required timing of compression facilities.
A Streamline Based Reservoir Management Workflow to Maximize Oil Recovery
Authors: Giordano Ronald M. , Jayanti Shekhar , Chopra Anil , Yuan Hua , Asakawa Kazuhiro , Suleimani Ali , Gheithy Ali , Edwards Clement
Published: December 2007

This paper presents a novel approach to integrated reservoir management in a mature carbonate field. The Lekhwair field (Oman) has been on production since 1976. It has a complex development history, with periods of primary recovery, shut-in, 5-spot, inverted 9-spot, and line drive waterflooding. The challenge is to develop two reservoirs, separated by a shale barrier, using a combination of commingled vertical and horizontal wells.

This paper presents a robust and proven reservoir management workflow that can be used to evaluate short to medium term development scenarios proposed by production technologists. Traditionally, reservoir engineers make medium to long term field development decisions based on complex reservoir models, while production technologists make short term well level decisions based on operational data. As a result, the reservoir engineers and production technologists frequently work independent of each other. This paper provides the workflow and techniques that enable reservoir engineers and production technologists to work in an integrated manner and thereby increase production and recovery in a mature field.

An integrated reservoir management workflow was developed that can help not only the reservoir engineer to understand the reservoir dynamics, but also the production technologist to evaluate everyday production opportunities. This evaluation is brought about by integrating streamlines from finite-difference simulations, well performance data, and novel performance diagnostic plots. This approach was successful in developing a dynamic model for the Lekhwair field. The proposed workflow and applications provide efficient ways to maximize oil recovery in a seamless workflow between reservoir engineers and production technologists.

This paper presents a combination of conventional and innovative techniques that provide a novel workflow for reservoir engineers and production technologists to quickly evaluate various reservoir development scenarios.
Optimal Well Placement for Production Optimization
Authors: Wang Chunhong , Li Gaoming , Reynolds A. C.
Published: December 2007

In the process of reservoir development, we always wish to drill wells at optimal locations so that more hydrocarbons can be extracted at a lower cost. Because well locations in a reservoir simulator are commonly treated as discrete variables, standard implementations of gradient based optimization is difficult so the optimization for this problem is normally done with a non-gradient based method such as the genetic algorithm. Here, we present a novel idea to convert the problem of optimizing on discrete variables into an optimization problem on continuous variables for the optimal well placement. The idea is to initialize the problem by putting a well in every grid-block and then optimize NPV. As the cost of "drilling a well" detracts from the NPV, when NPV is optimized some wells will be shutin (eliminated). For two very simple cases where the problem is to determine the optimal location of a water injection well, we show this problem formulation yields good results with a single injection well remaining after the optimization process.