bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Performance of Propellant / Perforating Technologies to Enhance Placement of Proppant on High Risk Sand Control Completions
Authors: Folse Kent C. , Dupont Richard L. , Coats Catherine G. , Finley Doug , Nasse David B. 
Published: December 2007

Abstract
The combined use of propellants and perforating for production enhancement is not new to the petroleum industry, especially for natural completions in competent formations. When used together, the propellant is shaped in the form of a cylindrical sleeve that is positioned over a scalloped perforating carrier to combine the perforating and stimulation processes into one step. The perforating event is performed in either an under-balanced or balanced condition, followed immediately with the extreme over-balance or rapid-gas pulse generated from the propellant burn. This technique provides an effective method to ensure that all perforations are sufficiently broken down from the fracturing to accept either produced or injected fluids.
This paper will review a new application for the combined propellant / perforating technique that has been successfully used in unconsolidated formations in the Gulf of Mexico.
The propellant / perforating technique was used to enhance the placement of proppant during frac-and-pack and gravel pack treatments while perforating in a balanced condition. The propellant / perforating technique was used on several formation types; i.e., long intervals, highly deviated, and highly laminated with extreme permeability contrasts, that would traditionally be deemed as high risk for proper sand placement.
In performing this technique, the propellant sleeves are positioned across the lower quality portions of the intervals with low permeability and resistivity to ensure that the perforations in these intervals would be broken down to accept fracturing fluids and proppant during the fracturing treatment consistent with the entire treated interval.
Case histories from Gulf-of-Mexico operators have shown that this technique is effective in both underbalanced and overbalanced perforating situations. With the trend in the industry to reduce cycle time, the elimination of the underbalance/surge process to ensure clean perforations and all the associated rig time in obtaining control of the well following the surge are seen as significant opportunities for rig-time savings.
It has also been proven that combining propellant/ perforating in a balanced scenario can offer a cost efficient and safe method when used as a near wellbore clean-up tool for pre-frac preparation or high rate water packing.
Multilateral Work-Overs: A New Possibility with Coiled Tubing
Authors: Ravensbergen John 
Published: December 2007

Abstract
The number of fields that are being developed, or redeveloped, using multi-lateral wells to enhance the effective drainage from minimal surface facilities is increasing. Some of these types of wells have complex Level 3, or higher, junctions but the vast majority are still Level 1 junctions.
Often drilling and other damage can be imposed on the various exposed leg well bores, as in the case of a Level 1 junction, while the other branches of the well are being drilled. This formation near well bore damage can, in the extreme, lead to a re-evaluation of the field development strategy as there has been no intervention method available to enter the various branches and perform effective stimulation or clean-up and, therefore, achieve the full production potential from the well.
This paper describes a new Bottom Hole Assembly (BHA), enabling a new method to workover multilateral wells using coiled tubing. The BHA and its method of navigating through multi-lateral wells makes the assumption a smart and/or selective entry completion is not installed in the well. Therefore, the onus is on the BHA to intelligently navigate through a junction(s) whether it is an open hole or cased hole. The BHA's operational success however, is dependent on the geometry of the junctions.
Examples from case studies performed in Canada Venezuela will be used to explain how the geometry is critical for successful operation of the tool. In addition, these case studies will explain what type of workovers have been tested and proven and what further possibilities exist.
The Application of PEM Drilling Fluid System in Environmentally Sensitivity Area
Authors: Shaocheng Xu , Jin Xiaojian , Zili Li , Xiang Xinjing 
Published: December 2007

Abstract
The PEM water-base polymer mud system was developed to provide an environmentally acceptable drilling fluid that approaches the inhibitive performance of an invert oil emulsion fluid.
PEM is engineered with a specially formulated PF-JLX additive for maximum shale inhibition and designed to drill high-angle wells in reactive formations, normally reserved for an oil-base mud. The primary functions of the PF-JLX in the system are to improve shale stability and the lubricity of the fluid.
Wellbore Hydraulic Optimization With Positive Displacement Motor and Bit
Authors: Samuel G. Robello , McColpin Glenn 
Published: December 2007

Abstract
Over the last few years, use of downhole motors have increased dramatically to meet the challenges of horizontal wells and in particular, extended reach drilling, deep and ultra-deep water wells. With these wells pushing the limits of rigs and equipment it is imperative that motors be utilized optimally in the system. More often downhole motor pressure loss calculations are not explicitly included in the overall hydraulic optimization and bit nozzle selection with the available pump power. Generally a motor pressure loss is specified in the optimization calculation and the optimized nozzle sizes are selected. To enhance the method of optimization and make the system more effective, hydraulic optimization is required by taking into consideration various motor and drilling parameters. The key to an improved drilling system is a unified system approach that encompasses motor and bit. This paper presents a new approach to hydraulic optimization by including both the motor and bit. It enables us not only to calculate the optimal flowrate and optimal horsepower of the motor as a function of configuration of the motor but also to select the correct motor configuration. In addition, calculations are made for hydraulic horsepower per square inch encompassing bit and motor. The practical usefulness of the theory, backed by the fundamental and optimal analysis is demonstrated with numerical examples.
Use of Spreadsheet and Analytical Models to Simulate Solid, Water, Oil and Gas Flow in Underbalanced Drilling
Authors: Guo Boyun 
Published: December 2007

Abstract
Underbalanced drilling (UBD) technology is widely used in oil and gas industry for multiple purposes including minimizing formation damage and controlling lost circulation. One of the important tasks in UBD design is to predict bottom hole pressure under given drilling conditions. This task is very difficult when aerated liquids are utilized. Sophisticated computer programs are often required for this task. However, reliable computer programs are not always available for engineers who are in charge of UBD designs and executions. It is highly desirable to have spreadsheet programs that can accurately perform such predictions.
This paper presents three analytical models that are coded in a spreadsheet program for UBD hydraulics calculations. These three models cover multiphase flow of commonly used drilling fluids in three categories: 1) air, gas, mist, and unstable foam; 2) stable foam; and 3) aerated liquid. Comparisons of these models with field measurements indicated that these analytical models are accurate enough for UBD design.
Multi Year Gas Storage Deliverability Results Using a Proppant Surface Modification Agent
Authors: Kozera Gregory A. , Willis Stanley F. , Shaw J. Stanley 
Published: December 2007

Abstract
This paper presents post-fracture deliverability results for 56 gas-storage wells over a two- to five-year period. Of the wells studied, 32 had a surface modification agent (SMA) applied to the proppant during the hydraulic fracturing treatment. The other 24 wells included in this study had no additives applied to the proppant for sand flowback control.
The deliverability results from actual flow tests are used to evaluate how absolute open flows (AOF) held up over multiple injection and withdrawal cycles involving significant pressure differentials. The results are compared for the large data sets of wells that did and did not include the SMA in the fracture treatment. In general, the data set for wells that did not include an SMA have been through four or five complete pressure cycles. After some operational problems, the need for proppant flowback control became apparent, and later frac treatments usually included the SMA. The wells that included a SMA have been through two or three complete pressure cycles.
This study was completed to alleviate the operators concern about the long-term impact of the SMA on the well performance. While the SMA effectively achieved the short-term goal of proppant-flowback control, the operator was concerned that the fracture might be more prone to a reduction in conductivity or simple clogging.
Typically, a new product or process gets a lot of attention and study. Many times the well results are tracked only for a year or less and the product or process becomes common or discarded. Longer-term studies on a product or process are less common, perhaps due to time, manpower, cost constraints, personnel changes, and a variety of other reasons. Over time, information can easily get buried in a sea of data. Wells using the once-new product or process are forgotten unless a serious problem occurs. The reason the product or process was first used may even be forgotten if it solved the problem.
While results may vary from formation to formation, this longer-term look at the results of SMA, injected with the proppant, should help fracture treatment designers convince the skeptics that proppant-flowback control can achieve its immediate objective and match or exceed long-term performance expectations.
Evaluation of Laminated Formations Using Nuclear Magnetic Resonance and Resistivity Anisotropy Measurements
Authors: Shray Frank , Borbas Tim 
Published: December 2007

Abstract
Laminated formations create two major evaluation problems for petrophysicists. First is the classic low resistivity pay problem as seen in vertical wells. Layers of fine-grained sand, silt, and clay distributed within a hydrocarbon bearing sand will significantly reduce the apparent resistivity measured by an induction or propagation tool. The fine-grained layers hold high volumes of irreducible water, the sand will produce water-free oil or gas, yet the oil company may not even attempt to complete the zone. Second is the high angle well evaluation problem. The same laminated formation, when measured by an induction or propagation tool at moderate-to-high relative dip, will exhibit an increase in apparent resistivity beyond that which was measured in the vertical well. Again, the accurate calculation of water saturation and hydrocarbon volume eludes the petrophysicist. Both of these classic problems can be solved with a common methodology that combines nuclear magnetic resonance (NMR) and resistivity anisotropy measurements.
Case study wells are used to demonstrate two versions of this method. In the first version, horizontal resistivity (Rh) and vertical resistivity (Rv) are the initial inputs. With an assumption of the resistivity value of the silt-clay layers, we solve for the resistivity of the hydrocarbon bearing layers and the volume fraction of each layer. Water saturation (Sw) of each layer is calculated independently. Bulk volume hydrocarbon (BVH) of the entire formation is the sum of the products of the layer volume fractions and their respective BVH. The second version of the method uses the measurement of bound fluid volume from the NMR tool to determine the volume fraction of each layer. We then solve for the resistivities of both the silt-clay layers and the hydrocarbon bearing layers. The solution of BVH for the formation then proceeds as in the first method.
Wireline-Conveyed Through-Casing Formation Tester Preserves Casing Integrity
Authors: Burgess K. A. , MacDougall T. D. , Siegfried R. W. , Fields T. G. 
Published: December 2007

Abstract
Advances in formation tester technology and a novel electro-mechanical drilling technique have provided the oil industry with a new modular through-casing formation tester. The wireline-conveyed tester, which determines formation pressure and fluid content behind casing, has been developed in a joint project conducted by the Gas Research Institute and Schlumberger. More than 200 Tcf in gas resources are estimated to exist behind casing in the United States alone. To facilitate evaluation of these potential reserves, the tool was designed to make a hole through the casing, measure formation pressure, take fluid samples and then reseal the hole. This paper describes the tool features, applications and field test results.
Primary applications include detection of bypassed hydrocarbons, evaluation of potential pay prior to well abandonment, and formation testing under conditions where openhole testing and sampling are not feasible. Reservoir management applications include production monitoring, especially waterfloods and CO2 floods, and economic evaluation for selling and booking reserves. Secondary applications include detecting gas-collector zones in gas storage wells, and injecting or producing through a few small drilled holes (i.e., limited-entry steam injection).
The tool uses a flexible drill shaft to drill holes several inches deep through casing, cement and formation. Pretests, involving pressure drawdown and buildup flow periods, are performed as pressure is measured with both a crystal quartz gauge and a strain gauge. If desired, a formation fluid sample can also be taken at this time. A reliable mechanical plug seals the drilled hole in the casing, creating an effective seal to at least 10,000 psi of differential pressure (either direction). This service was introduced in October 2000 and is now completing field trials. This novel technique for measuring pressure and taking samples through casing provides the ability to assess pay without perforating the well and facing costly and often problematic cement squeeze jobs.
Multiseam Coal Stimulation Using Coiled-Tubing Fracturing and a Unique Bottomhole Packer Assembly
Authors: Rodvelt G. , Toothman R. , Willis S. , Mullins D. 
Published: December 2007

Abstract
In Virginia, coalbed methane (CBM) production can occur from as many as 25 seams with thicknesses from 0.5 to 6 ft. Fracture stimulations have evolved from single-stage, limited-entry designs to multiple stage treatments with corresponding increases in gas production as additional staging was added. For mechanical and economical reasons, three to five stages have been typical. With the introduction of an integrated coiled-tubing (CT) rig and a specially designed bottomhole packer assembly (BHPA), additional staging to cover individual coal seams is possible.
A five-well project in Buchanan County, Virginia was chosen for coiled-tubing fracturing (CTF). Job designs that use current fluid and proppant loading were modified for the injection rates and pressures expected in treating down 3,800 ft of 2 ⅜-in. coiled tubing. Treatment procedures, fluid systems, and treatment graphs are presented illustrating job designs used to treat 11 to 19 different stages in each of the five wells. Economics are presented for accessing additional productive coal footage and the resulting net present value (NPV) gained. Lessons learned and recommendations for improving the efficiency of CTF in the Appalachian Basin are included.
Proppants: Is Bigger Better or is Placement the Key?
Authors: Mack David J. , Myers Roger R. 
Published: December 2007

Abstract
Historically, 20-40 mesh frac sand has been used in fracture stimulation treatments in the low permeability Devonian Sands of the Appalachian Basin. Carrier fluids have ranged from straight water to gelled water to water-based foams to crosslinked gelled water and even to crosslinked foams.
Recent work in the very low permeability (&lt;0.1 md) Cotton Valley formation in East Texas has shown that the conventional wisdom of 20-40 mesh sand and high gel loading crosslinked fluids may not necessarily be the most effective treatment. 40-70 mesh frac sand and low gel loadings have proven beneficial. Although the Devonian Sands are not an exact match to the Cotton Valley, the very low permeability and low reservoir pressure make these sandstones a candidate for this type of treatment.
Using an industry accepted well productivity calculator and the parameters of a Devonian reservoir, the well production characteristics of various sand mesh sizes is investigated. This is only a small piece of the puzzle. Where proppant is placed in relationship to the productive interval(s) and effective fracture length are critical factors in the productivity of this type of reservoir.
A 3-dimensional fracture simulator is employed to demonstrate the improved efficiency attained in the placement of small mesh sand (40-70). Various carrier fluids are employed to place the sand. These results are then run through the well productivity calculator demonstrating the importance of proppant placement.
Although pound for pound a large mesh proppant will have improved conductivity, the deeper placement attained with smaller mesh proppants improves well potential. This paper presents this data and develops a case justifying a change in conventional Devonian Sand fracture stimulation philosophy.
Technology Development: "Detecting Research and Technology Development Needs in a National Oil Company"
Authors: Domínguez-Vargas G. , Camacho-Velázquez R. 
Published: December 2007

Abstract
The purpose of this paper is to describe the findings of a technological diagnosis to detect research and technology development needs in a national oil company, the set of actions taken to solve these needs, and the evaluation of these measures by another needs- identification procedure. Using these results, future actions are proposed to consolidate the advances and to drive the company to the next level of technological performance.
An Expert System for Predicting Asphaltene Deposition
Authors: Lababidi Haitham M. S. , Garrouch Ali A. , Fahim Mohammad A. 
Published: December 2007

Abstract
Asphaltene precipitation from crude oils can cause serious problems in the reservoir, wellbore, and in the production facilities. A variety of models are available in the literature for predicting the onset of asphaltene precipitation from live crude oil. These models have been proposed based on different microscopic theories. Each of these models has its own limitations due to the inherent assumptions built-in. This study combines two of these models in conjunction with heuristic rules of thumb into a fuzzy expert system for predicting asphaltene precipitation. We developed three independent fuzzy evaluators. These are evaluators of precipitation potential from a refractive index, a solubility model based on the theory of Flory and Huggins, and a general-rules-of-thumb evaluator. Each evaluator is associated with a weighting factor to determine the final expert opinion about the potential of asphaltene deposition.
Control of Hydraulic-Fracturing-Induced Formation Damage by Optimizing Treatments With Constraints
Authors: Rahman M. M. , Rahman M. K. , Rahman S. S. 
Published: December 2007

Abstract
Uncontrolled growth of hydraulic fractures and initiation of secondary multiple fractures may occur due to execution of a fracture treatment with inappropriate values for various treatment parameters: fracturing fluid viscosity, injection rate, injection time and proppant concentration. Such uncontrolled fracturing is not only uneconomic due to increased treatment cost but may also damage the formation irreversibly, resulting in productivity lower than even unfractured wells. Also excessive pressure drawdown during production from hydraulically fractured wells may result in sand production due to mechanical failure of perforation tunnels. This paper presents an integrated model to optimize treatment parameters in order to achieve maximum possible Net Present Value (NPV) while the above mentioned formation damage aspects are avoided by satisfying various constraints. These constraints are formulated as functions of treatment parameters, fracture geometry and mechanical and petrophysical properties of the reservoir so that the critical conditions that induce the formation damage in different modes do not become active. Additional constraints are also formulated to ensure that the optimally designed treatment can be executed in the field by using the specified surface equipment, and fracture width restriction does not occur. A genetic-evolutionary computing algorithm is integrated to solve the constrained treatment design problem such that it finds optimum values for treatment parameters and fracture geometry that are formation compatible. The capability of the model is demonstrated in the paper by application to a gas reservoir.
Frac-Packing Openhole Completions: An Industry Milestone
Authors: Saldungaray Pedro M. , Troncoso Juan , Sofyan Muhammad , Santoso Bambang T. , Parlar Mehmet , Price-Smith Colin , Hurst Gary , Bailey William 
Published: December 2007

Abstract
Although frac-packing has been widely and successfully used in cased-hole completions, open-hole frac-packing is not so common. It is well known that the efficiency of cased-hole frac-packs can be limited by the perforations. It can therefore be expected that open-hole frac-packing would provide higher productivity by eliminating a major choke in the flow path. In this paper, we present an open-hole frac-pack case history involving a highly-deviated, challenging well in South East Asia and demonstrate the expected efficiency gains.
The well was drilled in a field with a major water-flooding program. Due to extremely low reservoir pressure, low fracture-gradient and high kh formation (100,000 md-ft), very high losses were experienced. The presence of a high-pressure, reactive shale above the pay zone made it necessary to prematurely run a 7-in casing in order to isolate the problematic zone. However, due to the collapse of the reactive shale section, the casing was set above the target depth thereby exposing 70-ft of shale zone. Initial attempts to run the completion assembly failed due to the collapsed shales, resulting in a suspension of the well. After 4-months of water-flooding, partial re-pressurization of the reservoir was expected, and consequently a decision was made to complete the well with the open-hole frac-packing technique. In order to address complete coverage in a high kh zone completed as open-hole, the shunt technique was used. In order to prevent reactive shales from collapsing and mixing with the proppant during frac-packing, a cup-type packer was set inside the casing to divert flow through the shunt tubes and thus bypass the shale section. These procedures resulted in a complete pack of the entire, highly deviated open-hole interval, with an optimized tip screen-out as per design. The resulting PI of 13.4 bpd/psi compares favorably to cased-hole frac-packs (average PI of 2.5 with a best PI of 5.8), cased-hole gravel packs (average PI of 2.3 with a best PI of 4.7) and open-hole gravel packs (average PI of 10.0 and best PI of 19.6) in the same field, particularly considering the extremely high losses (thus the extent of damage) experienced during the drilling stage of this well.
Detailed procedures are given along with operation execution and production results. An extension of this technique to long open-hole horizontal wells (injectors and producers), using modified tool configurations, is also discussed.