bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Storage in a Depleted Gas/Condensate Reservoir in the Appalachian Basin
Authors: Aminian K. , Brannon A. , Ameri S.
Published: December 2007

A depleted gas condensate reservoir in the Appalachian Basin has been under investigation for possible conversion to a gas storage reservoir. When depleted gas condensate reservoirs are used for gas storage, the injected gas will pressurize the reservoir and will evaporate the retrograde condensate that is remaining in the reservoir upon completion of the primary production. This will result in significant compositional alteration of the withdrawn gas from the storage. The produced gas during withdrawal cycle must be processed to remove condensible hydrocarbons prior to pipeline transportation to prevent liquid drop out by retrograde condensation in the pipeline. The composition of produced gas will depend on the degree of mixing between the injected and the residue fluids.

To investigate the impact of the formation on the mixing, a compositional reservoir simulator was utilized in this study. The primary production history of the reservoir was first modeled with simulator using available data and the results of the data analysis. The phase behavior studies with Peng-Robinson equation of state (PR-EOS) provided a reliable estimate for reservoir fluid composition. Upon successfully history matching the primary production, the reservoir model was utilized to predict the composition of the withdrawn gas from the storage. Pipeline gas was injected into the reservoir and the reservoir was pressurized to its original pressure. Both vertical and horizontal wells were considered for injection to evaluate the extent of mixing among residue gas, residue condensate, and the injected gas. Subsequently, a withdrawal cycle was simulated to predict the liquid yields and gas heating contents based on the design of the surface facilities. The results of simulation study were then used to finalize the design storage field and surface facilities. The preliminary data collected after pressurizing the reservoir confirms the simulation results.
Innovations in Drilling Using Replaceable Bits
Authors: Banerjee S. N.
Published: December 2007

In conventional drilling a majority of drilling problems occur during tripping such as key seating and wall sticking. This leads to increase in rig time hence cost is unnecessarily high, especially in deep sea drilling.

Conventional drilling techniques use rotary drill bits which need to be replaced depending on the formations encountered. If the formation is very hard, the bit has to be replaced by a diamond bit. These bit changes unnecessary increase trip time and eventually rig cost. This trip time which can take up to a day, especially for deep wells can be eliminated by using a novel "Replaceable Drill Bit" system.

The concept of replaceable drilling bits is attractive for deep drilling because of the high rig costs and the lengthy round trips needed to replace worn bits. These bits are sturdy, capable of withstanding the high dynamic loads imparted by the vibrating drillstring and are capable of operating with highly abrasive drilling mud containing large amounts of sand and drill cuttings.

Thus an entire hole can be drilled conveniently without frequent tripping operation to change the bit. Maximum efficiency can be achieved by this mechanism during drilling.
Using Induced Microseismicity To Monitor Hydraulic Fracture Treatment: A Tool To Improve Completion Techniques and Reservoir Management
Authors: Le Calvez J. H. , Tanner K. V. , Glenn S. , Kaufman P. , Sarver D. S. , Bennett L. , Panse R. , Palacio J. C.
Published: December 2007

The organic-rich shale gas fields underlying the Appalachian, Illinois and Michigan basins are potentially the most productive source of natural gas in the northeast United States. Similarly to the Barnett Shale in Texas and the Fayetteville Shale in Arkansas, considerable volumes of gas are currently produced from these unconventional Devonian shale reservoirs using traditional and more modern well log evaluations techniques and completion methods.

Among others, two main geologic factors govern the production from these gas-bearing formations: ultra low matrix porosity and permeability and fracture-induced permeability. Devonian Shales are extremely low porosity reservoirs that must be effectively hydraulically fracture stimulated. Additionally, analysis of these gas fields illustrates how structural geology (by the means of basement structure influence, differential shortening effect, etc.) yields stress field variations both laterally and with depth.

To avoid making too many assumptions as to the induced fracture geometry and to better understand the created fracture geometry for various completion designs, monitoring of the induced microseismic activity may be used. Using a couple of examples from various formations (e.g., tight gas sand, shale gas, etc.), this paper highlights how microseismic monitoring of hydraulic fracture treatments can provide key information to characterize fracture development and geometry.
Transient Behavior of Multilateral Wells in Numerical Models: A Hybrid Analytical-Numerical Approach
Authors: Aguilar C. , Alaska BP , Ozkan E. , Kazemi H. , Al-Kobaisi M. , Ramirez B.
Published: December 2007

This paper presents an extension of transient well index approach to simulate pressure transient behavior of multilateral wells. This approach uses an analytical solution for the well index at early times and switches to the numerical well index at late times. The use of the transient well index eliminates the need for excessive grid refinement around the well. In this paper, we have improved the accuracy of the transient well index approach and have provided for a flexible and easily implementable approach to place multilaterals in conventional, Cartesian-grid reservoir models.
Plunger Lift Optimization by Monitoring and Analyzing Wellbore Acoustic Signals and Tubing and Casing Pressures
Authors: Becker Dieter Joseph , Rowlan O. L. , McCoy J. N. , Podio A. L.
Published: December 2007

Plunger Lift operations are oftentimes not optimized due to lack of knowledge of plunger location and changes in tubing pressures, casing pressures and bottomhole pressures. Monitoring the plunger location in the tubing helps the operator to optimize the production of liquid and gas from the well.

In low liquid volume wells, the plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger falls through a tubing collar recess, an acoustic pulse is generated. These acoustic pulses, generated at the tubing collar recesses, travel through the gas in the tubing and can be monitored at the surface to obtain plunger depth. These acoustic pulses are converted to an electrical signal by use of a microphone or pressure transducer. The signal is digitized, stored and processed in a computer to determine plunger depth. In some high liquid volume wells, the acoustic pulses generated as the plunger falls past the tubing collar recesses may be masked and not detectable due to liquid accumulation around the plunger. However, in both low and high liquid volume wells, the plunger depth can be determined by generating an acoustic pulse in the tubing at the surface, and monitoring the acoustic reflection from the top of the plunger. Multiple shots are taken, so the plunger descent rate can be determined throughout the plunger fall.

Software processes this plunger depth data along with the tubing and casing pressure data to display plunger depth, plunger velocity and well pressures vs. time. Plunger arrival at the liquid level in the tubing, and plunger arrival at the bottom of the tubing are identified on the data plots. Well inflow performance is calculated and plotted.

Software displays the data and analysis in several formats including a pictorial representation of the well showing the tubing and casing pressures, plunger location, gas and liquid flow rates in the tubing and annulus, and inflow performance relationship at operator selected intervals throughout the cycle. A field case is presented to show how this field data analysis is applied to optimization of Plunger Lift operations.
Novel Approach for Estimating Pore Fluid Pressures Ahead of the Drill Bit
Authors: Jones John , Matthews Martin D. , Standifird William
Published: December 2007

The use of forward basin models in pore pressure prediction for well planning offers several advantages over conventional techniques. The extension of this technique to enable real time updates of pore pressure estimation ahead of the bit as new data becomes available represents a significant improvement in modeling that allows decision makers to be proactive instead of reactive during well construction.

Pressure-purposed basin modeling technology has been applied during real time drilling in ten wells. Success is measured through minimal differences between the post well interpretation to the pre-drill and periodic updates of the model.

This analysis revealed the pre-drill predictions from the pressure-purposed basin model were within 0.5 ppg over the entire drilled depth in three wells. Two of these three wells were updated during drilling in an attempt to maintain a closer tolerance. A fourth well was accurately predicted in an alternative stratigraphic scenario but the incorrect model was chosen as most likely. The remaining six wells were updated multiple times as new data from the well invalidated the previous predictions. Overall, 80% of the ten wells were within 0.5 ppg for the first 2000 feet after update, 90% were within 1.0 ppg. As distance from the last update increased, the accuracy of the prediction generally decreased depending on the particular conditions in the well.
Development and Utilization of a Bit-Based Data-Acquisition System in Hard-Rock PDC Applications
Authors: Pastusek Paul , Sullivan Eric , Harris Tommy
Published: December 2007

Drill bits are iteratively developed for specific applications to meet performance objectives such as aggressiveness, durability, stability, steerability, etc. The transition from one iteration to the next occurs when dull bits are examined, run data is analyzed and the inferences are implemented as revisions to the bit design and/or the operating parameters. Experience has shown that the efficiency of the process depends strongly upon the appropriateness and significance of the data collected. If, for example, a dominant cutter failure mechanism is incorrectly characterized as abrasive wear and is, in fact, impact wear, then the proposed solution and the development time will both be significantly affected.

One method for improving the significance of the data collected is to implement a special-purpose data-acquisition system within the bit. Such a device has at least three significant advantages over available sub-based data-acquisition systems: (1) its bit-based sensors will more accurately detect bit-based events, (2) it can be economically deployed over many bits and (3) it is relatively transparent to the user.

The paper describes an effort to develop, validate, and utilize a bit-based module designed to monitor accelerometer and magnetometer sensors and to record selected data. The authors also describe the effort to infer dynamic dysfunction(s) from the data in the fast-growing hard rock PDC bit application and to mitigate them via modifications to drilling parameters and bit designs.
Kikeh Batch Setting: Case Study
Authors: Flannery Chris , Choo Benjamin
Published: December 2007

The semi-submersible rig Ocean Rover was used by Murphy to batch set 23 wellheads in 4,350 ft water depth with zero Health, Safety and Environment incidents.

The batch set team worked together to maintain safety, performance, and to overcome numerous logistical and operational challenges. Implementing lessons learned and development of recommended practices resulted in continuous improvement throughout the project.

The program was completed in 63 days. Average installation time for conductor and surface casing was 3.36 days from start to finish. Total materials used were 50,000 ft of casing, 3,060MT of cement, and 78,000 bbls of 16.6ppg DKD mud.
Perforating for Fracturing—Best Practices and Case Histories
Authors: Pongratz Reinhard , von Gijtenbeek Klaas , Kontarev Roman , McDaniel B. W.
Published: December 2007

In 2004, SPE 90238, "Perforating and Hydraulic Proppant Fracturing in Western Siberia, Russia," provided recommendations for perforating in Western Siberia,1 an area where hydraulic fracturing is booming and considered second only to the North America region, with over 5,000 fracturing treatments performed each year. One of the issues that has become obvious over the past two years is the limited understanding of the importance of using well and reservoir data as major factors in the selection of perforating programs to prevent premature screenouts.

In recent years, several operators have concluded that maximizing production from most wells in western Siberia fields requires the placement of large quantities of coarsesized proppant using the least damaging fluid systems possible in the fracturing applications. For production optimization, the proven trend is "larger (proppant sizes) and bigger (jobs)" using the lowest acceptable polymer loading in the frac fluids to minimize gel damage.

To achieve successful placement of the designed optimized fracturing treatment, all factors that could lead to a premature screenout should be eliminated. Improper perforating practices have proven to be one of the primary limitations and are often proven as the number one reason for past screenouts. Using the preferred perforating guns and charges for a specific application reduced the total screen-out percentage to less than 5%. The key to proper selection of perforating methods included using API RP 19B data and simulation software that calculates downhole conditions.

This paper describes several case histories in moderately hard and moderately soft rock reservoirs, using both big hole and deep penetrating guns, showing results that proved using proper perforating practices could eliminate screenouts. Furthermore, the authors describe how a different approach (hydrajet perforating) was used to provide entry from the wellbore to the formation. Hydrajetting will be compared with conventional (shape-charge) perforating techniques prior to hydraulic fracturing. Case histories for multi-zone pin-point stimulation will be provided.
Streamline Simulation for Reservoir Management of a Super Giant: Sabiriyah Field North Kuwait Case Study
Authors: Ibrahim Muhammad N. , Clark Robert A. , Al-Matar Bader S.
Published: December 2007

This paper discusses the incorporation of Streamline simulation into the Reservoir Management Processes of the super giant Sabriyah oil field.

For the Middle East region, streamline simulation has particular significance due to the magnitude of reserves and scale of development. Streamline simulation brings immediate added value, due to its ability to handle high-resolution full three-dimensional models with hundreds of thousands to millions of cells, incorporating large amounts of field and well events over substantial operation periods, be they historical (i.e. history-matching phase), immediate (i.e. on-going) or in the future (i.e. prediction phase). This technology can be used to guide and optimize development strategy.

By incorporating streamline technology into existing and new reservoir development planning, we are able to demonstrate significant benefits and added value.

This paper will conclude with an analysis and discussion of some of the results accrued from the incorporation of streamline technology in the case under review. These include:

Reduced cycle time, leading to many more iterations of the entire decision-making workflow. Faster scenario analyses and decision-making. Better understanding of intra-reservoir communication. Better understanding of producer – injector relationships. Development planning for both producers and injectors.

This paper also demonstrates where streamline technology should fit within the overall reservoir management processes:

How the streamline simulation technology fits into reservoir management workflows. Where this technology fits into reservoir management workflows. What are the general benefits derived from incorporating and using this technology in reservoir management. When the streamline technology should be considered in reservoir management.
A Need for Converting Produced Waters to Useable Waters
Authors: Holliday George H.
Published: December 2007

There is a perennial and long standing lack of potable and useable irrigation water in the Western United States. U.S. oil and gas operators dispose of billions of barrels of produced water per year. The coalbed methane (CBM) operations produce about 825 million barrels of low salinity produced water per year. To a large extent, CBM is produced in the Rocky Mountain States, a large portion of the western states. Some of the CBM produced water is beneficially used, but the majority of the produced water is injected into subsurface formations or used without treatment for irrigation. There is an obvious need for potable and useable irrigation water in the western states. Also, there is an obvious over supply of produced water being injected into subsurface formations or being used for harmful irrigation purposes. Having a litigious society poses a restraint on Exploration and Production (E&P) operators who consider desalinating produced water. However, that same constraint is not imposed on state governments, who could purchase the produced water, ship the water to treatment plants and sell the water as potable and useable irrigation water after treatment.

Currently, state and federal agencies are encouraging use of untreated produced water for irrigation. This use of saline water destroys soil structure, kills vegetation, and eventually will result in litigation against producers. Constructive use of CBM produced water is needed. Converting the produced water into potable and useable irrigation water is needed and could be profitable for all concerned.

Viable produced water treating/desalinization methods are available and tested. Government agencies support the concept, but have offered no financial or regulatory help. The probability of legal action against E&P Operators for perceived or suspected adverse impacts from the desalinated water is too great for the industry to sponsor treating of produced waters. Thus, the states must assume that responsibility. There is a desperate need for potable and irrigation waters in the western states. Government needs to be encouraged to take the lead.
Improving Security on Offshore Installations
Authors: Struthers Donald , Esson George , Ferguson Ronald
Published: December 2007

"Improving Security On Offshore Installations"

Without question, the offshore oil and gas industry is vitally important to the global economy. It is an industry that operates worldwide, often in what is described as ‘hot spots’ or high-risk areas. Therefore it is clearly essential to ensure robust measures are in place to safeguard the industry's assets and people against unlawful acts, be these attacks of terrorism or from any other form of criminality. Achieving that leaves no room for complacency; therefore "Improving Security On Offshore Installations" should be a clear objective of all involved in the industry.
Prediction of Permeability Reduction Rate Due to Calcium Sulfate Scale Formation in Porous Media
Authors: Tahmasebi H. A. , Kharrat R. , Masoudi R.
Published: December 2007

Water injection is usually associated with various types of mineral scale formation and deposition which significantly undermine the performance of the injection by changing some reservoir properties such as permeability and porosity. Mineral scale deposition in surface and subsurface petroleum streams is one of the main concerns affecting the economy and safety of any production scenarios.

Among various types of mineral scales, calcium sulfate is one of major scales in petroleum industry that can cause sever flow assurance and formation damage issues. Many parameters are affecting this problem. Temperature, pressure, fluid concentration, ratio of brine to hydrocarbon, fluid dynamic and type of porous media are among these parameters. Interpretation and prediction of permeability reduction in such complicated system is very complex.

In this work an experimental and theoretical study has been conducted to investigate the permeability reduction due to CaSO4 scale formation. For this purpose, brine solutions containing calcium and sulfate ions were injected in a packed glass beads porous media at elevated temperatures and various flow rate and brine concentrations. The pressure decline and permeability changes were measured in all the conducted tests. It was found that the permeability reduction by calcium sulfate scale formation follows a systematic trend considering various above mentioned important parameters. Hence, a novel empirical equation has been suggested, which can predict permeability reduction rate with high accuracy to experimental data.
Incorporating Multiphase Behaviours in Dynamic Simulation Models Using in-Situ-Generated Pseudofunctions
Authors: Al-Busafi Bader , Al-Siyabi Zaid , Fisher Quentin
Published: December 2007

This work presents the use of pseudoisation to account for faults using practical representations of the multiphase behaviour of fault rocks within production simulation models The work starts by revisiting the conventional representation of fault sealing capacities in simulation models using transmissibility multipliers (TMs). TMs, as proposed by Manzocchi et al. (1999) are absolute and phase-independent values that are used to take into account the presence of fault-rocks within production simulation models and are calculated based on the fault thickness and absolute permeability, as well as the size and properties of the undeformed grid-blocks adjacent to faults. The crucial limitation of TMs is that they do not take into account the multiphase behaviour of fault rocks, whose relative-permeability and capillary-pressure curves can have very different characteristics to their juxtaposed host-rock curves.

This paper presents and tests a practical representation of the multiphase behaviour of fault rocks within production simulation models using in-situ-generated pseudofunctions. The generated dynamic pseudofunction curves are attached to the upstream cells of the faults using an analogous method to that proposed by Manzocchi et al. (2002). This method takes into account in-situ fractional flows and compartmentalised phase pressures across fault faces between non-neighbour connections. The proposed method gives very promising results when applied to a 3-D, two-phase model with fault-rock thicknesses ranging between 0.5 and 3 ft, and typical fault rock permeabilities (0.1-0.01) mD
Wettability Evaluation of the Unayzah Reservoir in Central Saudi Arabia
Authors: Okasha T. M. , Al-Saleh S. H. , Al-Khudair W. S.
Published: December 2007

Unayzah Formation in Central Saudi Arabia is an important source of light (48-52 API gravity) sulfur frees (0.02-0.07%) crude oil (Arabian Super Light). In 1989, the first oil discovery was made at Hawtah. Subsequently, a number of other oil discoveries were made at various fields (Umm Jurf, Ghinah, Nuayyim, Hazmiyah, etc.). Oil production from Central Saudi Arabia fields started in August 1994. As part of special core analysis program to support reservoir management in development of these fields, intensive SCAL studies were completed and crucial data required for field simulation were provided to proponents.

This paper summarizes the results of a set of consistent methods used in determining wettability of Unayzah reservoir. Both quantitative methods (Amott, USBM, and contact angle) and qualitative method (oil/water relative permeability) were used to evaluate the variation of wettability in Central Saudi Arabia fields. In this work, direct wettability tests were carried out on a large number of native core plugs from Unayzah reservoir. Moreover, several waterflood tests were conducted at reservoir conditions on composite cores using recombined reservoir fluids. Data from relative permeability curves were used for comparison with wettability results obtained from direct wettability tests.

Amott and USBM wettability indices indicated that Unayzah reservoir core material represented a range of wettabilities, but tended towards neutral to slightly to strongly water-wet. Contact angle results for rock material recovered from Unayzah reservoir showed water-wet characteristics for both oil-brine/rock system and oil-brine/quartz system. Moreover, the values of wettability indices are in agreement with relative permeability results which reflect a behavior of water-wet core material based on Craig's rule of thumb.1
Striving the Coil Tubing Limit Intervention on Snake "Long Horizontal" Complex Gas Well: Successful Perforation and Completion
Authors: Al-Araimi Nasser M. , Srisa-ard Surasak
Published: December 2007

Well A was drilled and completed in 2004 with smart intelligent completion. Total length of the well was nearly 6000 meter; it was very long complex horizontal "snake type" section (up to 3500 meter) with a smart completion, remote control of surface Flow-Control-Valves (FCV), Inflow Control Valves (ICV) for surface controlling of production from each zone, down-hole temperature and pressure gauges for monitoring each individual zone and A hydraulically controlled down hole choke (lower/upper valve) to control the inflow.

The well was completed in all upper sand packages. The upper two zones were perforated prior ran the completion using TCP (Tubing Convey Perforation) guns on drill pipe whilst rig is on site. The lower zones were to have been perforated after the completion was run, but there were completion difficulties such as plug could not be pulled to allow access the lower completion for further well intervention and completion i.e. logging and perforation.

This paper will show coil tubing operations success and challenges in a very complex horizontal "snake" type well for perforations and completion. Also setting up a milestone of Coil tubing confront and technical limit. Also will describe the processes, engineering and job execution associated with the successful running of CT in a very complex environment and pushing the CT limit envelope. Several innovative techniques were utilized; using coiled tubing tools, hydraulic jars and hammers. Overall, this paper is intended to share the knowledge and unique experiences gained during this innovative CT perforation and completion intervention on this well, which lead to the well to produce 2-2.5 million m3/d gas and 800 m3/d condensate.
Determination of Water–Producing Zones While Underbalanced Drilling Horizontal Wells—Integration of Sigma Log and Real–Time Production Data
Authors: Gauthier P. J. , Hussain H. , Bowling J. , Edwards J. , Herold B.
Published: December 2007

The paper presents a novel logging approach used to identify water producing zones while under-balanced drilling (UBD) horizontal wells. This approach will work in mixed-wet reservoirs and is particularly attractive for mature reservoir undergoing waterflooding.

The logging process consists of a standard logging-while-drilling (LWD) data acquisition followed by a pulse neutron capture run (PNC). The PNC data is acquired after pumping the tool inside the drillpipe to total depth (TD). The LWD-resistivity and PNC-sigma measurements are used to calculate completely independent oil saturation curves. This additional information is important for non-water-wet reservoirs because a separation between the resistivity and sigma-derived oil saturation will indicate a flushed zone. The separation is due to what is called resistivity hysteresis and is well documented in the literature and observed in the laboratory for this reservoir.

The logging information is complemented with real-time production data which provides a pseudo-inflow log of water and oil inflow intervals along the horizontal wellbore. The pseudo-inflow log is used to validate if saturation differences correlate with water production.

The approach is made possible because the wells are drilled under-balanced meaning that, during the drilling process, the reservoir pressure is always higher than the pressure in the wellbore. This pressure differential avoids drilling fluid invasion into the formation, which is necessary for shallow nuclear logging and allows the reservoir to flow for real-time production characterization.

Results from eleven UBD wells show that a positive correlation exists between inflow of water and separation between the resistivity and sigma-derived oil saturation. This is in agreement with the resistivity hysteresis concept.

This application can become important for projects developing mixed-wet reservoirs especially during the infill drilling or waterflood phases. The PNC logging operations takes between 6 and 12 hours and can be adapted with minimal incremental cost to most UBD operations.
The Velocity Field and Pressure-Drop Behavior in a Rough-Walled Fracture
Authors: Mou J. , Hill A. D. , Zhu D.
Published: December 2007

The transport of fluids down a hydraulic fracture is computed in fracture models by assuming some regular shape for the fracture. In the most complex 3D fracture models, each grid block is assumed to have parallel fracture walls. However, small-scale variations in the fracture width (or wall roughness) may increase the pressure drop, alter the 3D flow field, and, in the case of acid fracturing, influence the etching pattern along the fracture walls.

An accurate prediction of acid fracture conductivity necessitates the detailed description of the acid etching profiles on the fracture surfaces, which depends on acid transport in the fracture, leakoff due to local permeability, and acid/rock reactions. Although a 3D acid fracture model can predict nonuniform etching throughout a fracture, current computational limitations result in dividing the fracture into grid blocks that are several feet to tens of feet on a side, which is much larger than the scale of local heterogeneity and channeling characteristics. We are developing an intermediate-scale acid fracture conductivity model with grid sizes of a few inches to close the gap between laboratory-scale measurements of acid fracture conductivity and macro-scale acid fracture models. The key to such a model is the convective transport of fluid through a heterogeneous fracture.

This paper presents a method to calculate the 3D velocity fields for an intermediate-scale acid fracture model. Incompressible steady-state 3D Navier-Stokes equations describing the flow in a fracture with irregular boundaries are solved with a nonstaggered grid distribution. Leakoff on the fracture surfaces is specified based on local permeability. This model uses front-fixing method1 (body-fitted coordinate transformation) to transform an irregular physical domain into a regular computational domain. A spatially correlated permeability distribution and initial fracture width distribution are generated by a semi-variogram model.

Results from the model illustrate the complex velocity field that occurs in fractures with heterogeneous distributions of fracture width and leakoff rate. The global flow rate versus pressure drop behavior from this model is compared with the predictions of smooth-walled fracture models.
Innovative Methods to Improve Carbonates Reservoirs Modeling Accuracy and Reliability
Authors: David Foulon , Den Boer Louise , Vieban Florence , Noman Rashed , Labiadh Mohamed
Published: December 2007

While they already contain around half of the world's hydrocarbon reserves, carbonate fields still exhibit lower recovery factors than clastic fields. A major explanation lies in the more complex intrinsic structure and higher chemical reactivity of carbonate rocks. Because it is linked to both the depositional and the biological environment, the genetic pore network is more complicated than in classical sandstones. Moreover; it is usually strongly reworked after deposition by superimposed diagenetic processes as well as fracturing phases. This creates levels of heterogeneity orders of magnitude higher than in clastic environments. As a result, small scale heterogeneity is often a key driver of fluid flow in carbonates. Proper, reliable modeling of this critical heterogeneity remains a pitfall often preventing efficient reservoir simulation and development.

This paper recaps the traditional upscaling methods used for heterogeneity modeling, and highlights their limitations when applied to carbonates. It presents an innovative line of thinking to overcome these limitations, grounded on robust geological concepts and tied to core and log data. The corresponding reservoir modeling involves the dual porosity structure, not for fracture modeling, but for splitting the porous medium between the fluid portion mainly involved in pressure support and the one sweepable liable to be readily swept.

This innovative workflow, coupled to smart experimental designs matching techniques, was applied to a mature carbonate field in the Middle East. It enabled to reach a first-time successful history matching, and to highlight significant additional development potential. Conceptually simple and numerically efficient, this methodology could be extended to other highly heterogeneous fields.
Underbalanced Drilling Of a Horizontal Well in Depleted Reservoir: A Wellbore Stability Perspective
Authors: Qiu Kaibin , Gerryo Yousef , Tan Chee Phuat , Marsden James Robert
Published: December 2007

The need to reduce formation damage and to avoid differential sticking and lost circulation in depleted reservoirs favors the use of underbalanced drilling (UBD) technology. In highly depleted reservoirs, the pore pressure can be very low, necessitating the use of extremely low-density fluid to achieve an equivalent circulating density (ECD) below the pore pressure. In such situations, the stress redistribution around the wellbore has to be supported mainly by the rock matrix, and limited support is provided by the mud pressure. Therefore, UBD can dramatically increase the risk of wellbore instability.

From literature review, it was found that the techniques and methodologies to carry out wellbore stability analysis on UBD of horizontal wells are not well documented. This paper presents a wellbore stability study that was conducted to evaluate the feasibility of using UBD technology to drill a horizontal well in a highly depleted reservoir in Libya.

The study started with geomechanical laboratory tests and Mechanical Earth Model (MEM) construction to evaluate the in-situ stresses, pore pressure, and mechanical properties of the formations likely to be encountered during the planned UBD campaign.

Wellbore stability analysis was subsequently conducted for the planned horizontal well to be drilled underbalance using a new practical approach. The analysis revealed a high probability of extensive and severe breakout within the weak zones if penetrated underbalanced and the potential for massive wellbore collapse. Under the guidance of this study, the well plan and drilling designs were amended to minimize drilling risk.
Smart Cementing Solutions for Low BHCT Wells—Case Studies for Successful Field Implementation
Authors: Banerjee Satinath , Dasgupta Debasish , Suyan K. M. , Jain V. K.
Published: December 2007

Cement slurry designing using conventional cement additives for primary casing cementation of wells with low / moderately low BHCT (40 – 70 Deg. C) generally encountered in shallow wells or in wells located in mature / depleted reservoirs is an industry challenge. Cement slurries for field implementation needs to possess adequate placement time, minimum fluid loss, good rheological behaviour, minimum free water separation, short transition time, good stability and early strength development capability under operational conditions. However, even with all the recent advancements in cementing technology, till today simultaneously meeting all of above requirements is extremely difficult for slurries designed with conventional cement additives.

In many onshore mature fields in India where ONGC is carrying out development drilling for the past several years, low / moderate BHCT wells are encountered. Due to technical limitations, job execution with inadequately designed cement slurry using conventional additives have resulted in many a case of poor casing cementation. As a result it was required to perform remedial cementation to overcome the undesired situation.

Extensive investigations have been carried out at Institute of Drilling Technology (IDT) in ONGC to formulate suitable cement slurry systems for low BHCT wells where all cement slurry parameters could be controlled simultaneously. This paper presents details of slurry designing with conventional additives by the incorporation of low cost silica based pozzolonic material. Studies have culminated in the development of novel slurry systems with unique feature that is was possible to have simultaneous total control over all crucial slurry parameters which could not be done earlier. The performance of developed designs have been elucidated and validated by field implementation in an onshore field of ONGC.

In the lesser explored area of slurry designing for wells with low BHCT, this paper established a low cost high performance alternative by the use of silica based pozzolonic material.

Field implementation results arising from this study confirmed superior cement bond logs in comparison to earlier results with no requirement of repair jobs. The details of the development, case studies of successful field implementation along with conclusions and recommendations derived from this endeavor are presented in this paper.
In-Situ Combustion Technique to Enhance Heavy-Oil Recovery at Mehsana, ONGC - A Success Story
Authors: Doraiah A. , Ray Sibaprasad , Gupta Pankaj
Published: December 2007

The northern part of the Cambay Basin located in Mehsana, Gujarat (India), is fenced by a number of heavy oil fields reserving about 140 MMT OOIP. Balol and Santhal fields form a part of this heavy oil belt with API gravity 15-18. The oil viscosity ranging from 50 to 450 cps at reservoir pressure of 100 kg/cm2 and 700C temperature. High mobility contrast between viscous oil and water has resulted into low primary recovery. Subsequent Artificial lift methods resulted into high water production rather than oil. Thus, it necessitated for in-situ combustion technique.

In-situ combustion is a thermal enhanced oil recovery process. The technique is based on the principle of reducing viscosity by heating of oil in the reservoir itself. It involves ignition in the well and injection of air to sustain flame front. In this process a small quantity of in-place oil burns, producing CO2, water vapours and heat. It helps in lowering the viscosity of oil, which increases the oil mobility and displace it towards the surrounding producers.

It is a matter of pride that ONGC, Mehsana has successfully implemented this technology. The project was initiated at Balol field on pilot scale in 1991. Based on encouraging results, in-situ combustion technique was implemented on commercial scale in 1997 at Balol and Santhal fields. It has not only given a new lease of life to these fields but has also increased the oil recovery factor from 6-12% to 39-45%.

Production engineering for in situ combustion involves careful planning and monitoring for successful implementation. Based on field experience, some of the major issues which came up during implementation are summarized in this paper. It can be helpful for successful planning and implementation of new projects
A Practical Approach For Preventing Lost Circulation While Drilling
Authors: Suyan K. M. , Banerjee S. , Dasgupta D.
Published: December 2007

Lost circulation problems encountered during drilling is caused by the differential pressure of the hydrostatic column which is generally greater than the formation pressure, and is especially through the openings in the rock in low pressure or depleted zones. Combating circulation loss is often achieved by using variety of LCM formulations or placing the cementing plug. The quick set sealing cementitious composition is formulated that produces cuttings compatible to drilling fluid. An engineering approach applied with the cementitious compositions admixed with synthetic fiberous LCM placed at the thief zone in the well set into a cementitious plug. The fiber based slurry allows setting in high permeable or fracture zone and caused strong impermeable net to prevent the losses.

Results from a laboratory study on cementitious formulations are discussed and compared with Portland cement plugs. The cementitious formulation designed with GGBS and silica fume admixed with synthetic LCM formed a slurry which is activated with calcium hydroxide. The sealing effect of the formulation has been evaluated against the sieves and slots of different sizes. The results revealed the substantial improvement in sealing the thief zone. The study of thickening time and compressive strength of formulations having sp gr 1.4–1.6 has been carried out at 60 deg C to get sufficient pumping time and strength to resume drilling within 3-4hrs. The contamination of drilling fluid with cementitious compositions has no significant changes in rheology that saves the extra expenses for conditioning the drilling fluid.

The paper presents various formulations of cementitious compositions which can be used effectively and economically to combat circulation loss during drilling.
Using the Low Frequency Observation Data in Automatic History Matching
Authors: Faskhoodi Majid Mohammadpour , Kelkar Mohan
Published: December 2007

Integration of production data in reservoir description requires solving an inverse problem. Typically, a manual procedure is used to adjust the input parameters such that the productiodata can be history matched. Recently, many new techniques have emerged which try to accomplish this objective by using automated techniques. The two most common techniques involve gradient method and adjoint method. Both methods suffer from computationally demanding algorithms, except that gradient method is efficient if number of parameters is small and adjoint method is efficient if the number of observations is small.

In a typical history matching of mature reservoir, we are faced with large number of input parameters and large number of observations. This would make both the procedures inefficient.

This study proposes a technique to reduce the number of observed data so that history matching can be accomplished more efficiently. Using the low frequency information, we demonstrate that the history matching is more efficient. We further show that the low frequency data provides more robust estimate of input parameters compared to the use of all the available data. The proposed method is validated using a synthetic example as well as actual field example.
Successful Innovative Water-Shutoff Operations in Low-Permeability Gas Wells
Authors: Chaabouni Hassan , Enkababian Philippe , Chan Keng Seng , Cheneviere Pascal , Falxa Philippe , Urbanczyk Christophe , Odeh Nadir
Published: December 2007

Water production from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells, leading to a considerable loss in recoverable reserves. In some cases, mechanical techniques provide a viable solution for shutting off water production, although often, such a solution will create a restriction inside the well, limiting access to deeper reservoir layers.

Even though chemical water shutoff chemicals and techniques are improving significantly, not many options are available to treat high temperature and low permeability reservoirs. It may prove difficult to squeeze cement slurries and different types of gels into such formations owing to constraints of particle sizes or fluid viscosity. It is a challenge to get a squeezable fluid into low-permeability reservoirs that will be effective in sealing the near-wellbore area and be able to withstand high differential pressure while producing. Another challenge is to determine a placement technique to prevent excess displacement of the treatment, to minimize further intervention into the well, to clean any residual treatment from the tubing, and to minimize water damage to highly sensitive producing layers.

This paper presents successful case histories of treatments that were performed to shut off water producing layers characterized by low permeability. It describes innovative techniques that were developed for this special project. The treatments were placed using coiled tubing, and only one run was required to shut off the zones in question.
Linking Well-Test Interpretations to Full Field Simulations
Authors: Al-Thawad Faisal M. , Liu Jim S. , Banerjee Raj , Agayapong Domonic
Published: December 2007

The objective of this study was to investigate a workflow where well test data could be used more effectively in history matching of full-field reservoir simulation models and also in situations where existing simulation models could be used in well test interpretation.

The need to effectively use information available from well test analysis in full-field simulation has long been recognized. However, only limited benefit could be obtained by reconciliation of the analytical well test model with the numerical full-field model. We present a more complete approach where a more integrated approach using a common model is advocated.. The benefits of such a workflow can be summarized as follows:

Improved well test interpretation by using simulation models that have been built using geological, geophysical, petro-physical, and dynamic data. Improved history matching of simulation models by incorporating transient pressure data. Use common data models like fluid (PVT) and SCAL data.

Existing commercial well test and near wellbore modeling software packages, were used to carry out this task. These packages provide engineering interfaces to the simulator that make their respective workflows easy. However, there were a number of situations where manual intervention and workarounds were necessary. We would like to propose an easy to use software that can provide a complete workflow for regular use.