bluuebunny/crossref_metadata_2025 huggingface dataset:
Distributed Temperature Sensing (DTS) Enables Injectivity Visualization to Enhance Stimulation Efficiency
Authors: Fahim Mohamed , Keshka Ashraf , Marzooqi Ayesha Al , Alvi Aman , Salem Dalia , Brown George , Neyaei Fardin Ali
Published: September 2011

Carbonate coiled tubing (CT) reservoir stimulation approaches vary, using acid systems and different diverters in order to try to achieve the best results. However, because it was not previously possible to know where the injected fluids actually go in the formation during a stimulation job, even with the enhancement of the coiled tubing placement and software model prediction, the results were often not effective as they could be.

The inclusion of a fiber optic distributed temperature monitoring system (DTS) in the coiled tubing enables visualization of different zones injectivity by monitoring the exothermal effect of the acid reaction with the carbonate in highest permeability zones and hence acid and diverter placement can be optimized for improved stimulation efficiency.

In one of Abu Dhabi Onshore fields a production log (PLT) was run in a water injector well that was completed in two different reservoirs, to provide a baseline injection profile. The acid stimulation job was then performed using fiber optic temperature monitoring through the coiled tubing, to optimize fluid placement.

One feature of the data acquired by the fiber optic distributed temperature system was that the initial baseline temperature log was able to identify the high permeability injection interval from its "warm-back" response and this was correlated with the PLT interpretation. Consequently the treatment volume was optimized using the DTS results. Another DTS run was recorded after the acid stimulation with diverter using the injection velocity approach. This consists of bull-heading water down the coil tubing annulus and tracking the hot water generated at the heel of the well from the previous shut-in as it moves across the reservoir. The velocity interpretation of the injection profile confirmed that there was minimal injection into the high permeability interval at that point of time.

The stimulation resulted in a well injectivity increase of 20% indicating successful placement and diversion of acid compared to conventional stimulation practices. The use of DTS will enable stimulating wells without the need for pre-job production log (PLT) and especially wells where a PLT is not possible either due to low flow-rates (below critical flow) or operational constrains (completion restriction).

This paper details this "first-time" experience of a coiled tubing stimulation combined with DTS measurement and injection velocity profile in the UAE. It also concludes with a list of lessons learnt and recommendations for similar future approaches.
Optimum Subsurface Production Management, Abu Dhabi, U.A.E
Authors: Kenawy Maher M. , Al Katheeri Abdulla B. , Hafez Hafez H. , Stenger Bruno A.
Published: September 2011

A prolific mature reservoir Unit-Y producing since the early seventies was subdivided into two major flow units, an Upper sub-zone (USZ) with Darcean permeability and a Lower sub-zone (LSZ) with permeability averaging a few tens of milliDarcy. This reservoir is part of a super giant onshore carbonate oil field undergoing secondary peripheral water flooding and operated by ADCO about 110 km southwest of Abu Dhabi. The Upper sub-zone (USZ) of the reservoir witnessed a very efficient piston-like waterflood in spite of some early water breakthrough since the early eighties due to the presence of high permeability vuggy streaks difficult to detect on conventional logs and usually not recovered during coring.

Since the late nineties, the Lower sub-zone (LSZ) was the target of an intensive development involving two hundred horizontal producers with a 3000’ long 6" openhole reservoir section. With a relatively moderate horizontal permeability, the main flooding mechanism in the Lower sub-zone (LSZ) was identified as the slumping of water from the flooded areas of the Upper sub-zone (USZ) after production drawdown from the producers in the Lower sub-zone (LSZ) was larger than the slightly negative oil-water capillary imbibition threshold initially preventing the gravity-controlled downward movement of water.

The unusual aspect of this inverted water coning situation brought a focus on the determination of the optimum production rate for the horizontal producers located in the Lower sub-zone (LSZ). A maximum production rate of 1500 blpd was assigned to the Lower sub-zone (LSZ) horizontal producers until field observations (production logging, repeat saturation logging, multi-rate testing, fiber glass casing) and the results of two pilots batches including twenty seven producers set at a higher production rate could be used to calibrate reservoir simulation models. All data acquired and studies performed over the last ten years have shown that these horizontal wells could be safely produced at a higher rate with no adverse effect on the water breakthrough timing, planned ultimate recovery or well integrity. The adoption of this higher production rate resulted in a major optimization of the business plan requirements at a time of high rig demand and with an increasingly busy surface running out of new drilling locations.
A Methodology to Determine both the Technically Recoverable Resource and the Economically Recoverable Resource in an Unconventional Gas Play
Authors: Madani HusamAdDeen S. , Holditch Stephen
Published: September 2011

During the past decade, the worldwide demand for energy has continued to increase at a rapid rate. Natural gas has emerged as a primary source of US energy. The technically recoverable natural gas resources in the United States have increased from approximately 1,400 trillion cubic feet (Tcf) to approximately 2,100 trillion cubic feet (Tcf) in 2010. The recent declines in gas prices have created short-term uncertainties and increased the risk of developing natural gas fields, rendering a substantial portion of this resource uneconomical at current gas prices.

This paper quantifies the impact of changes in finding and development costs (F&DC), lease operating expenses (LOE), and gas prices, in the estimation of the economically recoverable gas for unconventional plays. To develop our methodology, we have performed an extensive economic analysis using data from the Barnett Shale, as a representative case study. We have used the cumulative distribution function (CDF) of the values of the Estimated Ultimate Recovery (EUR) for all wells in a given gas play, to determine the values of the P10 (10th percentile), P50 (50th percentile), and P90 (90th percentile) from the CDF. We then used these probability values to calculate the technically recoverable resource (TRR) for the play, and determine the economically recoverable resource (ERR) as a function of F&DC, LOE, and gas price. Our selected investment hurdle for a development project is a 20% rate of return and a payout of 5 years or less. Using our methodology, we have developed software to solve the problem. For the Barnett Shale data, at a F&DC of $3 Million, we have found that 90% of the Barnet shale gas is economically recoverable at a gas price of $46/Mcf, 50% of the Barnet shale gas is economically recoverable at a gas price of $9.2/Mcf, and 10% of the Barnet shale gas is economically recoverable at a gas price of $5.2/Mcf. The developed methodology and software can be used to analyze other unconventional gas plays to reduce short-term uncertainties and determine the values of F&DC and gas prices that are required to recover economically a certain percentage of TRR.
Reservoir Optimized Fracturing - Higher Productivity From Low- Permeability Reservoirs Through Customized Multistage Fracturing
Authors: Finkbeiner Thomas , Freitag Hans-Christian , Siddiqui Mohammed , Woudwijk Roy , Joseph Kevin , Amberg Firman
Published: September 2011

Economic exploitation of low-permeability or tight sandstone and carbonates can be an elusive endeavor. New technologies and approaches are needed to make these more challenging reservoirs economically attractive. The completion technique discussed in this paper has been successfully employed in previously non-economic gas reservoirs in North America. The main focus of this completion technique is enhanced reservoir connectivity with the wellbore. Other completion techniques have previously been used to successfully improve reservoir contact and enhance production. These techniques are similar in their focus on improved reservoir connectivity by compartmentalizing the wellbore into multiple sections. They do, however, have their limitations in low-permeability or tight formations.

The novel completion technique presented in this paper involves horizontal drilling through a reservoir combined with compartmentalizing the wellbore into multiple sections. Each wellbore section is then individually fractured in order to effectively propagate fractures through the reservoir, thus greatly increasing productivity in each zone. Up to twenty-four zones can be set up, allowing operators to customize their stimulation program in long-reach horizontals in heterogeneous and low-permeability reservoirs. Detailed knowledge of the existing natural fracture network, the current-day stress field, and geomechanical considerations are key inputs to a valid reservoir model, reducing the risk of establishing undesired flow paths with the aquifer, for example.

This paper will illustrate how this new technology has enabled operators to benefit from significant economic improvements through operational efficiencies achieved during the drilling and completion phase based on reduced rig time and faster, more cost-efficient completions. Water shutoff options available with this new type of approach will also be discussed. Multistage fracturing leads to higher initial production, improved reservoir drainage, better control on fracture propagation, and controlled production from fractures in low-permeability sandstone and carbonate reservoirs as well as in gas-shales, which will be illustrated with case histories from these operating environments
Proactive Scale Mitigation Strategies for Simple to Complex Multilateral Producers in a Saudi Arabian Carbonate Field
Authors: Raju K. U. , Baruah K. , Al-Otaibi N. M. , Al-Shammari F. G.
Published: September 2011

Calcium carbonate is the most predominant scale in Saudi Aramco crude producers. Conventional phosphonate based scale inhibitor treatments are highly effective in carbonate formations. Application of new research findings in the company’s modified scale inhibitor squeeze treatment programs has significantly improved the treatment life at the lowest possible cost. These modifications resulted in better post-squeeze well response compared to more conventional treatment. However, in spite of the success of scale inhibitor treatment in vertical and conventional horizontal wells, addressing the placement of chemicals in long horizontal and complex producers, such as multilateral, maximum reservoir contact (MRC) and extreme reservoir contact (ERC) wells is always challenging and cost intensive.

A drop in operating pressure at a gas-oil separation plant (GOSP) from 450 psig to 250 psig in a carbonate field necessitated a proactive scale inhibitor treatment program. A comprehensive scale mitigation study was conducted to prioritize the treatments based on the severity of the scaling potential for all the vertical, deviated, horizontal, multilateral, and MRC wells as part of the company’s scale mitigation strategy. Conventional bullheading of chemicals from the surface into all laterals and selective lateral treatment after comprehensive lateral testing was executed as part of the trial test campaign. This paper describes/illustrates well selection criteria for priority treatment methods applied for simple to complex wells, comparison of pre- and post-production results, and a discussion of the current ongoing optimization program.
Miscible CO2 Injection in Highly Heterogeneous Carbonate Cores: Experimental and Numerical Simulation Studies
Authors: Aleidan Ahmed , Mamora Daulat
Published: September 2011

We have conducted a miscible CO2 flood using carbonate cores and 31° API west Texas oil under four injection modes: simultaneous water and CO2 (SWACO2), water alternating CO2 (WACO2), continuous gas injection (CGI), and waterflood (WF). Then, a pseudo-miscible black oil simulator was used to match the experimental results. The matched simulation model was extended to conduct a sensitivity study on permeability variation in the core, WACO2 ratio and slug size, and SWACO2 ratio. Three permeability values were chosen to represent a flow barrier, average matrix permeability, and high permeability streak. These values were arranged to represent a layered reservoir and then aligned in series to represent a sequenced reservoir. The four injection modes were conducted in all six permutations of these three values in both the layered and sequenced arrangements.

The oil recovery from the coreflood experiments was measured to be 90, 86, 75, and 54 % of OIIP for SWACO2, WACO2, CGI, and WF, respectively. The simulation results may be summarized as follows: for all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. Conversely, lower recoveries were obtained when the barrier was not in the middle and the high permeability was located at the top with significant decrease in oil recovery (up to 40%). In sequenced reservoirs, each injection mode showed different preference to the permeability arrangements. For example, CGI showed higher recovery (5% increase) when the low permeability is near the outlet which allowed for more controlled displacement but with high differential pressure across the core. The WACO2 ratio study in the homogenous (base) case showed that a 1:2 ratio had the highest oil recovery but the optimum ratio was 1:1 based on the amount of injected CO2. In layered reservoirs, each permeability arrangement had higher recovery at different WACO2 ratios depending on the location of the flow barrier. However, in most cases 1:1 ratio was the optimum except for two cases, where the high permeability was at top, the 3:1 (increasing water ratio) was the optimum WACO2 ratio.
New PDC Technology Improves Drilling Performance and Sets New Penetration Record in Raageshwari Field, Rajasthan, India
Authors: Upadhyay Abhishek , Chowdhury Ashabikash Roy , Borgaonkar Rohan
Published: September 2011

Raageshwari field is located in Rajasthan province in northwest India and an operator has been actively engaged in a development drilling campaign since 2009.

The ongoing drilling campaign involved drilling vertical wells of approximately 3000 m deep. The final 6–in. hole sections of these wells were approximately 600 m long and passed through abrasive claystone of about 5,000 psi unconfined compressive strength (UCS) and very hard and abrasive volcanic tuff of 23,000 psi UCS.

Initially, the operator used a PDC bit to drill the claystone, but it was unable to penetrate through the hard volcanic tuff resulting in a costly trip for bit change. To drill through the volcanic tuff, the operator used an impregnated bit with turbine resulting in a very slow penetration rate (ROP). It was apparent that new improved bit technology was required to save the trip and to improve the penetration rate.

After a detailed study of the formation properties and testing several bit design iterations, a new PDC bit with improved cutter technology was selected. Various technology features for balling prevention, stability, hydraulics efficiency, and depth of cut control were incorporated in the design to improve the drilling efficiency.

Upon deployment, the new PDC bit drilled the entire claystone section and 75% of the volcanic tuff section. A detailed design and run review of this bit resulted in an improved design with new wear-resistant cutters and higher sharpness retention capability. This bit drilled the entire 6-in. section of the target well with an overall penetration rate that was three times faster than before, setting a penetration record among the wells drilled in the field.

The authors will present the various technologies that were incorporated in the PDC design and demonstrate their benefit towards drilling efficiency improvement.
Pulsed Neutron Monitoring of the First CO2 EOR Pilot in the Middle East
Authors: Al-Aryani Fatema , Obeidi Adel , Brahmakulam Jacob , Ramamoorthy Raghu
Published: September 2011

Using borehole measurements to monitor carbon dioxide (CO2) floods in the reservoir is essential to properly understand the behavior of the injected fluids and the flow patterns. Pulsed Neutron logs provide essential measurements for the evaluation of saturation in the injectors, producers and observers. However, the CO2 environment is as yet uncharacterized in the industry. Hence, reliable inferences require that either the measurement is immune to the borehole environment or that the perturbation is minimal and can be easily corrected. Where corrections are required, suitable benchmarks should be planned in advance to verify the accuracy of the corrections. These corrections should be based on the physics of the measurement to the maximum extent possible.

On the first CO2 EOR pilot project in the Middle East—unique in the world because the CO2 flood was implemented with the reservoir at original oil saturation—several pulsed neutron surveys were recorded in the injector, observer, and producer wells. The surveys included capture and inelastic mode acquisition. Several novel techniques of data acquisition and interpretation were successfully tried. This paper presents the steps in planning and executing the jobs and the results of the surveys. Limitations of existing characterization and those imposed by the measurement environments in the subject wells are discussed and we show, through comparison with benchmarks, that correction for the unusual borehole environment is possible. The paper illustrates how the different modes of pulsed neutron data acquisition complement each other in the individual wells in assessing the borehole environment, providing adequate input data to enable a multiphase reservoir fluid analysis, and yielding independent fluid saturations for effective comparison. The results of the analysis are compared with an openhole evaluation to help create a coherent picture of the reservoir.
Pushing the Envelope for Polymer Flooding Towards High-temperature and High-salinity Reservoirs with Polyacrylamide Based Ter-polymers
Authors: Vermolen E. C. , van Haasterecht M. J. , Masalmeh S. K. , Faber M. J. , Boersma D. M. , Gruenenfelder M.
Published: September 2011

Polymer flooding is a mature EOR technique successfully applied in both sandstone and carbonate reservoirs and it is expected to have much wider applications in the future. However, it is currently limited mainly by a combination of reservoir temperature and make-up brine salinity and hardness, as synthetic polymers can chemically and thermally degrade at high temperature and salinity.

This paper reports the results of an ongoing study aimed at finding polymers that can enlarge the application envelope of polymer flooding to, for example, high-temperature and high-salinity Middle Eastern carbonate reservoirs. In this study thermal stability of a number of commercially available polymers was tested at 120°C in various brines. The polymers investigated are partially hydrolyzed polyacrylamide (HPAM) based co- and ter-polymers functionalized with 2-Acrylamido-2-Methylpropane Sulfonate (AMPS) and/or n-Vinyl Pyrrolidone (n-VP) monomers. These monomers provide tolerance to divalent ions and protection to hydrolysis at higher temperatures.

The thermal stability tests showed a clear relationship between the polymer stability and the concentration of the functionalizing monomer. Incorporation of the AMPS monomer alone does not stabilize the polymer in brines which contain divalent ions. The additional incorporation of n-VP demonstrates a stabilizing effect which is optimal at a concentration of 35-50%. The optimal ter-polymer is stable at 120°C in brines with salinity up to 200,000 ppm TDS and divalent ion concentration up to 18,000 ppm for more than 180 days.

Another challenge to polymer flooding is the adsorption of polymers onto the reservoir rock. The adsorption of the terpolymers on carbonate core material was investigated in this study as a function of the polymer type and pH.

This is the first work to prove the feasibility of polymer flooding at temperatures up to 120°C in high-salinity reservoirs in the presence of a high concentration of divalent ions. These results will significantly enlarge the application envelope for polymer flooding.
Identifying Minor Faults and Demarcating Compartments in Areas of Large Seismic Anomalies using Time-lapse OWC Mapping - Example From the Super Giant Greater Burgan Field, Kuwait
Authors: Al-Enezi Hamdah S. , Bardalaye Jayanta , Al-Azmi Khalid , Aqeel Anfal , Al-Humoud Jamal , Al-Haddad Saud M. , Belal Dawood
Published: September 2011

The Greater Burgan Field in Kuwait consists of three culminations – Burgan Dome in the south, Ahmadi in the northeast and Magwa in the northwest. The Cretaceous Burgan Formation is the main reservoir of the Greater Burgan Field. The major part of the reservoir consists of massive, stacked, fluvial channels with an active bottom water drive. The structure is dissected by a number of faults resulting in compartmentalization of the reservoir. The major faults are easily mappable with seismic data. However, mapping the minor faults is a challenge due to velocity anomalies present in the shallow formations masking the structural picture at the Burgan Formation level.

Hydrocarbon saturation logs are widely used in the field to monitor the movement of the oil-water contact (OWC). At many places, uneven OWC rise is observed, that cannot be attributed to different offtakes from the wells. Time-lapse mapping of the OWC by different vintages of hydrocarbon saturation logs, in combination with open hole logs, shows that these differences can only be explained by sub-compartmentalization along structural discontinuities. Such discontinuities are mostly observed in the Magwa area where shallow velocity anomalies are also more pronounced.

Mapping the trends of these discontinuities shows that they are aligned to the regional fault trends mapped seismically. Using this technique, a number of minor faults can be mapped that sub-divides the major compartments into smaller ones. This will help in better positioning of in-fill locations and also in refining the production strategy of the compartments.
Systemizing People - Systems to Manage People OR People to Manage Systems?
Authors: Ahmed Nabeel
Published: September 2011

"System is down, cannot approve your expenses!"; "You have missed the system deadline for performance evaluation!"

How many of us have heard one of the above or related remarks? Perhaps we all have and it truly reflects our reliance on technology and systems to manage our most important asset i.e. Human Capital. In our attempt to adapt technology and succeed in the race to improve productivity, the basic principles of Human Resources management may have been rather undermined.

The rigorous demands of the service industry and scarce time resources have enhanced our dependency on HR systems. Whilst the thought of using technology to efficiently manage processes impacting our employees is on the face of it an intellectual one, it is gradually steering us from the true rationale. For instance, a performance management system can provide for accurately recording employee’s goals and performance results; however, it cannot and should not replace the communication session an employee has with his or her manager which has the true potential of increasing performance.

This paper is an attempt to highlight the correlation between the number of HR systems used and its impact on managing human resources. And while evaluating the impact, the thought is in no way to suggest that computer based systems are worthless, but to examine if multiple systems in HR are really good for an organization.

Today’s services industry presents an increasingly challenging and competitive business environment. With these dynamics, the most significant differentiating feature of a successful organization will be a motivated and engaged workforce. It is therefore critical to avoid dependency on HR systems alone and focus on the basic principles of Human Resources management to connect with employees.
Numerical Interpretation of Single Well Chemical Tracer Tests for ASP Injection
Authors: de Zwart A. H. , Stoll W. M. , Boerrigter P. M. , van Batenburg D. W. , Al Harthy S. S.
Published: September 2011

A series of single well injection tests has been conducted to estimate the efficiency of Alkaline Surfactant Polymer (ASP) flooding. These injection tests comprised a Single Well Chemical Tracer (SWCT) test that was done after water injection to establish a baseline remaining oil saturation and a second SWCT test conducted after ASP injection to measure the Remaining Oil Saturation (ROS) after ASP.

Analytical methods are generally used to interpret SWCT tests and to determine the remaining oil saturation. These techniques work best when the response is close to an ideal, single peak. However, the responses from the SWCT tests in our single well tests sequences are complex, showing multiple peaks. This is indicative of complicating factors such as cross-flow between layers. To understand the complex response we used numerical simulation techniques to interpret the SWCT tests. The numerical model includes the physics of ASP, such as interfacial tension reduction, water viscosity modification, and the related reduction in ROS as wells as an accurate model for tracer dispersion. The model allows full control of physical dispersion and does not require the use of numerical diffusion to mimic the effect of physical dispersion. The numerical simulation sequence involves the full single well injection test history including SWCT tests before and after the ASP injection.

The key challenge in matching the tests results with the numerical simulations was to model the complex response, which was different for each well tested. Elaborate numerical simulations, different from the conventional interpretation method, were used to successfully match all tests. This paper presents the simulation work, an explanation of the parameters varied to obtain agreement between numerically predicted and actual SWCT responses and the numerical simulation tools used to match the SWCT tests.
Pressure Transient Testing Under Multiphase Flow Conditions
Authors: Kamal Medhat M. , Pan Yan
Published: September 2011

Although pressure transient testing technology was developed assuming single phase flow in the reservoir, multiphase flow conditions are the norm rather than the exception. The single-phase flow assumption is valid for oil reservoirs above the bubble point pressure with no water production and relatively dry gas reservoirs. For oil reservoirs below the bubble point pressure, gas condensate reservoirs below the dew point pressure and fields producing water, the multiphase flow effects should be considered in transient test analysis. Several attempts have been reported in the literature to handle multiphase flow effects (e.g., Perrine 1956, Martin 1959 and Raghavan 1976). A recent multiphase testing method to calculate the absolute permeability of the reservoir and the average fluid saturations at the time of a transient test has been proposed (Kamal and Pan 2010). This paper briefly describes the three methods, presents results of using them to analyze example synthetic data and shows a field example illustrating lessons learned and best practices to use the recent approach.

The recently proposed method has been validated through analyses of synthetic data and, as the field example shows, that the same absolute permeability calculated when a field was producing only oil above the bubble point pressure, was obtained when the reservoir pressure dropped below the bubble point and both oil and gas were being produced. Another example leads to the same conclusion when an oil field is producing under oil-water two-phase flow condition and water saturation changes at different stages of the field life. A major advantage of the method has also been illustrated (Kamal and Pan 2010) through yet another field example where it showed how to separate the effects of various factors (e.g., multiphase flow, compaction, etc.) on changing the value of permeability.
Novel Foamer Application for Enhanced Oil Production
Authors: Debord Saet Byul , Lehrer Scott , Means Nancy , Crosby Simon
Published: September 2011

As a well ages, the reservoir pressure decreases and the liquid starts to accumulate at the bottom hole. Without reducing the hydrostatic head via deliquification technology, production would more rapidly decrease than the natural decline curve and would cease completely. In gas fields, foamers are very attractive deliquification technology as they are relatively economic and flexible technology. Conventional water-based foamers have been very successful for deliquifying wells to enhance gas production and reducing hydrostatic pressure. However, there has been very little success in treating oil-loaded wells with foamer due to the difficulties in foaming crude oil.

Novel chemistry that foams crude oil was identified, and a new oil foamer was developed as a solution for oil-loaded wells. This oil foamer was tested in wide range of crude oils and water cuts to determine the type of liquid that the new oil foamer treats cost effectively. Lab tests showed that the new oil foamer effectively treated liquid with an API gravity range of 25~40 and a water cut up to 60 percent.

A field trial at an EOG well in South Texas proved that the new oil foamer increased gas and oil production. Historically, this well produced intermittently due to low reservoir pressure. The average production prior to the field trial was 40 BOPD and 250 Mcf/D when the well produced. Average oil and gas production for the 60-day period prior to oil foamer injection was only 13 BOPD and 122 Mcf/D.

Lab tests determined the recommended dosage of the oil foamer and defoamer, and the dosage was optimized during the field trial. The oil foamer was applied continuously through a capillary at a rate of 750 ppm after optimization. The defoamer was injected at the wellhead to control the foam issue at the surface equipment. The oil foamer application increased production from 7 days to 12 days. Gas production increased from 122 Mcf/D to 400 Mcf/D, and oil production increased from 13 BOPD to 100 BOPD. During the entire field trial, the defoamer successfully controlled the foam issue, and the foam did not pose any upset to surface equipment.
Case-Based Reasoning: Predicting Real-Time Drilling Problems and Improving Drilling Performance
Authors: Raja Hamayun , Sørmo Frode , Vinther Morten L.
Published: September 2011

Over the past decade, oil and gas service companies have implemented real-time operations and remote surveillance centers to reduce the non-productive time (NPT) associated with wellbore integrity and downhole failures. Despite these efforts, NPT remains at around 15 to 35% of the total well cost. Companies seek to reduce NPT with knowledge management systems collecting best practices, knowledge cubes along the wellbore, and lessons learned. On the other hand, drilling activities are inherently data intensive, and as the amount of available data increases, it makes it correspondingly difficult for engineers to interpret the situation in a short period of time.

Case-based reasoning (CBR) is a method that can use the real-time drilling data to index and automatically recall the various experiences that are now only available through dedicated knowledge management systems. Using this method, human experience can be collected in a company case base, linked to observed data, and automatically brought forward in real time when it is again relevant. In this paper, we introduce the CBR method and discuss some of the challenges in applying this method to drilling data. The DrillEdge computer system, based on this methodology is introduced, which uses the WITSML standard for drilling data acquisition, integration, and mass storage, making it possible to use in an integrated environment with current real-time operations and remote centers. It will also highlight the importance of a unique user interface to interpret the real-time results during drilling operations.

An evaluation of the system was performed in which the system learned to recognize and, subsequently, predict problems when historical data from several land-drilling operations in Latin America were played back as simulations. A rigorous testing routine was applied to evaluate the capability of the CBR system to correctly identify potential risks and provide the user with remedial actions within a specified time-critical window.
Experimental Study of CO2- and Methane- Foam Using Carbonate Core Material at Reservoir Conditions
Authors: Aarra M. G. , Ormehaug P. A. , Skauge A. , Masalmeh S. K.
Published: September 2011

Foam has been applied to improve sweep during gas injection or for gas shut-off, and also for cleaning of contaminated underground formations. In this paper, foam properties have been evaluated for applications in carbonate material. The emphasis has been to investigate CO2 foam, and therefore, methane and CO2 based foam has been compared. Several foam experiments have been performed at high temperature and high pressure, respectively 100 °C and 277 bars in Limestone outcrop and carbonate reservoir cores. The foams ability to block or reduce mobility of unwanted gas and water is also target of the investigation.

The surfactant, C14/16 Alpha Olefin Sulfonate (AOS), ability to generate foam was influenced by the salinity of the injection water. Moderate to strong foam was generated both for CO2 and CH4 foams in limestone core material using 0.5 wt% surfactant concentration at seawater salinity. Mobility reduction factors at end of experiments for the different core floodings were in the range of ~ 13 to 43. The generated foams showed good ability to reduce gas and water production at low pressure gradients. In high saline formation water foam formation failed in limestone outcrop core material.

For the carbonate reservoir core material, foam generation was influenced by the injection method. The preferred injection would be co-injection of gas and surfactant solution, but this method failed to generate foam. However, when pregenerated foam was injected, CO2 foam was observed at the outlet end of the reservoir core.
Quantification of Remaining Oil Saturation Using a New Wireline Dielectric Dispersion Measurement - A Case Study from Dukhan Field Arab Reservoirs
Authors: Al Qarshubi Ibrahim , Trabelsi Ali , Akinsanmi Mustapha , Polinski Ralf , Faivre Ollivier , Hizem Mehdi , Mosse Laurent
Published: September 2011

The accurate determination of remaining oil saturation (ROS) for Qatar Petroleum’s Dukhan oil field, under production since the 1940s, is a key requirement for an ongoing revision of the field development plan. In 2009 several dedicated observation wells were drilled and cored. Extensive wireline data acquisition of nuclear, resistivity, acoustic, and nuclear magnetic resonance (NMR) data was performed with the objective to quantify the remaining oil saturation from log measurements and compare these log-based results with remaining oil saturations from core analysis.

The Dukhan field is under water flooding for secondary recovery, and changing water salinities resulting from the mixing of salty formation and fresh injection water make any resistivity-based calculation of remaining oil saturation a difficult task. Faced with these challenges Qatar Petroleum chose to field-test a new wireline dielectric dispersion tool to obtain resistivity independent remaining oil saturation information. A second objective was to test the estimation of Archie’s cementation factor m from dielectric dispersion measurements, as Qatar Petroleum had evidence that m varies vertically and laterally across the reservoir.

Remaining oil saturations obtained from the dielectric dispersion tool are presented and compared with resistivity-based values, NMR diffusion-relaxation analysis results, and core-derived Dean-Stark oil saturation measurements. The results confirm the ability of the dielectric dispersion tool to give a reliable measurement of remaining oil in place. Estimation of Archie’s cementation factor m appears to confirm expected variations especially in the Arab-C reservoir in certain parts of the field, with the dielectric dispersion based remaining oil saturation agreeing with the observed fluid production.
Perforating Long Horizontal Section with Tractor Brings Significant Gains in Completion Efficiency
Authors: Badri Mohammed , Al-Hashami Ahmed , Al-Masroori Mohammed , Salsman Alan , Jumaat Mohd Shafie , Situmorang Haposan
Published: September 2011

Oman completion strategies continue to evolve as more cased horizontal wells are completed. These wells must be perforated and, for the best production performance, should be completed underbalance avoiding any kill as part of the process. Early wells were perforated using coiled tubing with mechanical sealed ballistic connector1 to shoot in underbalance conditions and retrieve the gun assembly without having to kill the well. While the use of Coiled Tubing is a very effective deployment method, the extreme trajectory of some wells requires that fluids to ease drag friction be pumped as part of the deployment process. These friction reducing fluids may damage the perforations resulting in poor productivity.

A new wireline tractor conveyance technology designed for the harsh, high shock application of perforating has been used to perforate a long horizontal well section in underbalance conditions. Detailed pre-job planning and modeling was carried out to ensure the job could be executed as desired. Also the "lessons learned" gained in a previous attempt to use this technology helped improve the delivery efficiency. The guns were deployed and retrieved under controlled conditions minimizing any perforation damage in addition to significantly reducing the running times compared to other conveyance methods used in previous wells.

Eighteen successful tractor runs were made deploying up to 18.9 m of 2 7/8" OD perforation guns per run shooting 253m of perforation interval. Operating time was reduced significantly compared to previous perforating operations and no additional formation damage was done to the perforations as part of the process. Subsequent well productivity was better than expected.

The success of this operation opens up a wide range of applications for perforating or other heavy duty and high shock applications for this tractor technology. In the future different deployment technologies can be combined with the tractor for conveyance to push even longer gun strings into highly deviated wells in "live well" conditions further improving completion efficiency.This paper will review the technical considerations and the detailed planning exercise that is required for a successful tractor perforating job as well as the operational requirements to minimize nonproductive time (NPT). This in turn will improve job planning and the likelyhood of operational success for future perforating jobs in this complex operating environment.
Integrated Well and Reservoir Surveillance in the PDO EOR Projects
Authors: Zwaan Marcel , Hartmans Rob , Saluja Jasmeet , Schoofs Stan , Rocco Guillermo , Saadi Faisal , Lopez Jorge , Ita Joel
Published: September 2011

PDO has implemented Enhanced Oil Recovery (EOR) methods including thermal, chemical and miscible gas injection projects in several fields. In the initial phase of these EOR projects, well and reservoir surveillance is key to increase the understanding of the effectiveness of the EOR processes in the various reservoirs. Well-planned and executed reservoir surveillance has proven in the past to add significantly to the production and ultimate recovery from reservoirs.

Because of progress in technology, in areas of data acquisition, processing and modeling techniques, well and reservoir surveillance data are increasingly used to optimize EOR processes. However, the interpretation of all data and integration into well and reservoir management workflows is still challenging. This paper describes the ongoing development of workflows for the interpretation, modeling and integration of surveillance data in three EOR projects. The surveillance methods include geomechanical modeling, thermal reservoir modeling, and monitoring through time-lapse seismic, surface deformation, microseismic, temperature, pressure and saturation logging.
Integrated Workflow for Computer Assisted History Matching on a Channelized Reservoir
Authors: Peters Elisabeth , Wilschut Frank , Leeuwenburgh Olwijn , van Hooff Peter , Abbink Oscar
Published: September 2011

Increasingly computer assisted techniques are used for history matching reservoir models. Such methods will become indispensable in view of the increasing amount of information generated by intelligent wells, in which case manual interpretation becomes too time consuming. Also, with the increasing possibilities for controlling a reservoir, a better prediction of the reservoir behavior is very important. A technique that has received considerable attention lately is the Ensemble Kalman Filter (EnKF), which is a sequential updating technique based on the Bayesian notion of updating prior information with observations (measurements). The EnKF has already been proven to be useful for history matching of real fields. Some of the advantages of the EnKF are its sequential nature, the large number of parameters that can be estimated (10000+) and the fact that an uncertainty estimate is generated. The most important and time consuming step for anyone wanting to do a history match with the EnKF is creating the initial ensemble including defining all the proper initial uncertainties. This paper presents an integrated workflow for creating an initial ensemble for a channelized reservoir and updating the ensemble sequentially using the EnKF. The resulting ensemble of history matched models is then used to predict the expected production and associated uncertainty for a new production strategy. The quality of the prediction is compared to the predictions from a model which was history matched manually. The improved predictive capabilities of the models which were history matched with the EnKF allows for better optimization of the production strategy for the complex channel geometry. Moreover, the updated uncertainty estimate shows the risks involved with some of the newly proposed wells, which allows for better decision making.
Adjustable Gauge Stabilizer and Torque and Drag Reduction Tools Reduce Overall Drilling Times by at Least 20%: A Case Study
Authors: McCormick John E. , Osorio German , Andachi Jorge , Barth Megan
Published: September 2011

Drilling more efficiently has always been an important consideration throughout the industry, but with the ever more complex and far reaching wells that are being drilled today, it has reached the stage of being a critical factor in the economic viability of many projects. This has lead to the development of many tools and techniques which have enhanced the overall process of drilling deviated wells and helped to realize significant savings in drilling time and improvements in well geometry.

Two such developments are the adjustable gauge stabilizer (AGS) and torque-and-drag reduction tools, which provide a method of reducing drilling times in directional wells with build and tangent sections, thereby decreasing the cost while mitigating risk. An AGS eliminates the need to pull and replace the bottomhole assembly (BHA) after completing the build section, thereby saving one complete round trip. Torque-and-drag reduction tools enhance the ability to make directional adjustments while rotating and facilitate reaching well targets which high levels of torque and drag would otherwise prevent. As a result, the time spent drilling with a positive displacement motor (PDM) without pipe rotation (sliding) in the tangent section is mitigated, reducing overall drilling time for the section by an average of at least 20%.

This paper will discuss the evolution, design and operational characteristics of these tools and will present case studies of wells drilled in Ecuador where either the application of both adjustable-gauge stabilizers and torque-reduction tools, or the application of an AGS reduced drilling time when compared to offset wells drilled with conventional directional assemblies.
After Closure Analysis an Underutilized and Undervalued Approach to Understanding kh
Authors: Rylance Martin , Judd Tobias , Makmun Areiyando
Published: September 2011

For low permeability tight gas reservoirs, the fracture half length and the fracture dimensionless conductivity are the two principal design parameters, goals and characteristics that can be set; that have the greatest impact on the actual well productivity index. The fracture dimensionless conductivity compares the ability of the fracture to convey fluids along its length into the wellbore, versus the capability of the reservoir to support the flow of fluids into the fracture itself. However, in most cases, and certainly in an exploration and appraisal environment, the formation permeability and effective permeability thickness (kh) are often misunderstood, miscalculated and misapplied; subsequently impacting the fracture design process and therefore the overall well performance.

A large part of this exploration and appraisal process includes understanding the nature of, and gathering accurate data on, the reservoir performance itself; so that engineers can make the necessary informed decisions. In terms of estimating an accurate value for the effective permeability, techniques such as pre-frac pressure build ups and pressure draw-downs are probably the most common approaches taken; however these approaches can be operationally time intensive and costly, awkward to effectively execute and the data open to wide and non-unique interpretation.

As a result, the industry developed (some time ago), the little used process of pre-frac injection tests; to help identify formation transmissibility and reservoir pressure. This operation consists of the injection of a small amount of fluid into the formation at low rates and accurately recording the formation response during the pressure decline. From analysis of this data, it is relatively straightforward to calculate the effective formation kh (to reservoir fluid), optimize the hydraulic fracturing design, improve the reservoir model and more accurately perform post fracture well diagnostics.

This paper presents the application and results of such after-closure analysis (ACA), the impact of these calculations on the subsequent fracturing operations and finally their integration into a more comprehensive understanding of the fracture/reservoir performance and deliveribility.