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Collaborating Authors
SPE Formation Damage Control Symposium
Abstract Formation damage, tubing plugging and plugged production equipment caused by the deposition of organic deposits and sludge are inherent in many workover and stimulation operations around the world. This paper describes the methodology followed to improve production through adequate stimulation treatments and control of the organic and sludge deposition existing in the south-east of Mexico. In fact, this is a recurring problem that has existed for many years severely affecting oil production. Evaluation of the results and conclusions derived at different stages of the analysis are discussed. The benefits of emulsifying the acid with an aromatic(external phase), are also presented including the key factor of the iron reducing agent in a ferric iron environment in addition to the required iron sequestering agent. Results of stimulations performed in the area are discussed including well performance months after treatments. Introduction Organic deposits and sludge problems are increasing in the petroleum industry. Their precipitation is a problem that has existed for many years in the south east of Mexico, severely affecting oil production. Oil production in the south east of Mexico is distributed between the tertiary sands, the Cretaceous and Jurassic dolomitic limestone's. These last two are found in the 5,000 to 6,200 meters (m) range with temperatures in the 125–155°C. The reservoir considered in this paper is characterized by natural fractures with a 35° API sludge tendency crude containing asphaltenes in the 10–15% range, paraffin in the 15–20% (High Molecular Weight) and 2-5% (Low Molecular Weight) causing routine deposition in the production equipment, tubing and formation. Until recently, the main approach for resolving the severe deposition of these organics has been remedial; i.e., routine injection of appropriate chemicals to dissolve the deposits. In fact, a good portion of the wells have a0.95 cm capillary tubing which is run with the production tubing for continuous injection of both asphaltene and paraffin dispersants to alleviate the problem. However, the persisting asphaltene-sludge precipitation problem was in need for another approach.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
SPE 31077 Optimizing Stimulation Treatments of Gravel Packed Wells by Analysis of Back Produced Fluids After Stimulation Terje Schmidt, SPE, Statoil, Torstein Haugland, SPE, Statoil, Jan Tuxen Thingvoll, Vestlandsforsking Copyright 1996, Society of Petroleum Engineers, Inc. Abstract A significant loss of productivity was observed in some of the first high rate gravel packed wells on the Gullfaks field. Productivity was initially restored by stimulation with clay acid (HBF4) and mud acid (HF/HCl) to remove and dissolve formation damage, believed to be caused by fines and clay. However, productivity soon decreased and frequent treatments with diluted HCl were necessary to maintain production from these wells. The paper discusses mechanisms that can contribute to the observed permeability reductions following shortly after each treatment. Evaluation of the HCl treatments revealed that large amounts of "AlF", "FeF" and CaF2 compounds, had formed as a result of the initial clay acid treatments. In one well, significant amounts of re-precipitated compounds of Al and Fe that could be attributed to the first acidizing job were detected up to 2 years later. Finally, the paper discusses how the treatments can be optimized based on the resulting increase in production rates and the chemical pattern revealed after stimulation Introduction The Gullfaks Field is located in the central part of the East Shetland Basin in the Northern North Sea (Fig. 1). The field is operated by Statoil on behalf of the Production License 050 consisting of Statoil (85%), Norsk Hydro (9%) and Saga Petroleum (6%). The field is developed with 3 Condeep platforms. Gullfaks A, B and C, and has been on production since December 1986. Current production is approximately 90 000 Sm3/D from 70 production wells, and approximately 60% of the 280*106 Sm3 recoverable reserves are produced. Estimated production life for the field, based on own reserves, is 20 years with peripheral water injection as the main drive mechanism. The oil is located within three major sandstone units. the Brent Group, the Cook Formation and the Statfjord Formation. The Lower Brent, comprising of the Broom, Rannoch and Etive Formations represents a prograding delta front. The upper Brent is comprised of the Ness and Tarbert formations. The Ness Formation represents a delta top sequence with minor mouth bars dominating, while the Tarbert Formation represents the retrieving delta front building a homogenous sandstone unit on the top. The reservoirs are overpressured, with an initial reservoir pressure of 310 bar at datum depth (1850 m below mean sea level), and a temperature of around 70 C. The oil is undersaturated with a saturation pressure around 245 bar varying with depth and location. All Gullfaks formations contain poorly consolidated sands with high porosity and a potential need for sand control. Until May 1989, sand strength prediction and selective perforation was the main strategy and considerable research was conducted to avoid sand production. In a number of wells, water break through caused severe temporary reduction of maximum sand-free rate, and the need for sand control was clearly realized. Since then, remedial action for sand control has been implemented in a total of 47 wells. Out of these, 30 are cased hole gravel packs and two are open hole completions (Fig. 2). With the exception of the first wells to be gravel packed, the gravel packed wells have performed very well, with no significant productivity decrease before sea water breakthrough and scaling problems occurred. This paper will concentrate on the experience with some of the relatively few wells that have needed regular acid treatments to maintain productivity; A-16A, A-23 and B-9 and where loss of productivity was not caused by scale. P. 41
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (18 more...)
- Well Completion > Sand Control (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Well Completion > Acidizing (1.00)
- (4 more...)
Abstract Estimation of completion pressure losses in gravelpacked and frac-packed wells is generally performed through use of empirical or semi-empirical analytical relations. This paper reports on work conducted by Conoco to compare numerical simulation results with analytical inflow performance relations. The work shows how and where completion pressure losses occur in flow to gravelpacked and frac-packed wells. A fine gridded finite difference model has been developed to simulate flow and pressure loss behavior in the reservoir/well system. The grid system employs elements as small as 1 cm to model complex near well and intra-well flow effects including near-wellbore flow convergence to perforations, flow distribution between perforations and flow through gravel-filled perforations. Those near-wellbore effects are reviewed for both symmetrical gravelpacked well flow cases and asymmetrical flow cases associated with frac-packed wells. Intra-well flow through gravel-filled perforation tunnels and the casing/screen annulus is also modelled for both cases. Pressure losses and skin effects due to damage, fracturing and wellbore geometry are calculated through the flow system and compared to predictions from analytical relations. Results of these comparisons lead to an improved understanding of the effects of damage and flow asymmetry on gravelpacked and frac-packed well performance. Further, they show how current analytical skin relations can be enhanced to provide more effective completion pressure loss predictions. Introduction Frac-packing is a relatively new completion technique in which a small fracturing treatment is combined with a cased hole gravelpack. The fracture is designed to increase well flow capacity, providing a highly conductive path to the well that effectively bypasses near-wellbore damage and minimizes radial convergence effects. The perforations, perforation tunnels and annulus between the gravelpack screen and the casing are then packed with sized gravel to prevent formation sand from entering the wellbore. This paper discusses a numerical simulation study of frac-packed completions conducted by Conoco's BDR-Technology Group. Study results provide insight into how frac-packed wells achieve high productivities and shows areas where they are most susceptible to damage. The paper breaks the study into three parts, corresponding to the major phases involved in the work.
- North America > United States (0.46)
- Europe > Norway (0.28)
Abstract This paper describes the successful application of the frac-and-pack completion technique to a low-permeability oil-bearing formation in coastal Zaire, West Africa. Using various completion methods since initial field development in the early 1970s, operators have recovered less than 1% of the estimated oil in place from this formation to-date. Encouraging results from a two-well pilot project initiated in late 1994, led to a decision to work over an additional four wells for frac-and-pack completions in 1995 as part of the pilot project. This work centers around the Turonian formation, which is a soft, low-permeability siltstone formation. The friable nature of this formation combined with a low median sand-grain size (20 to 40 microns) has led to formation sand and fines production in some wells. Past attempts to stimulate the Turonian through matrix acidizing have been unsuccessful, and completions of the reservoir with both open- and cased-hole gravel packs have shownun economical production rates. The first two frac-and-pack treatments of the pilot project, one in cased hole and one in a 15-in. underreamed open hole, were pumped through a short weight-down gravel pack assembly that allows for monitoring a live annulus during the job and accurate measurement of net fracturing pressures. The four additional frac-and-pack completions were performed with a similar downhole assembly. This paper highlights the main aspects of this project, including the reservoir description, completion equipment, fluid and proppant selection, design and analyses of the fracture treatments, and optimization of the treatments as the project progressed. A summary of well performance following the frac-and-pack completions is also presented. Introduction The Liawenda field is located onshore Zaire in the Congo basin of central Africa. This basin extends southward from Zaire into northern Angola and northward through Cabinda into the Congo Republic. Oil accumulations have been found throughout the basin in several formations.
- Africa > West Africa (0.61)
- North America > United States > California (0.28)
- Africa > Angola > Cabinda Province (0.24)
- Africa > Angola > South Atlantic Ocean (0.24)
- Geology > Geological Subdiscipline (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.68)
Abstract A numerical model has been developed that addresses both plugging of, and sand production through single wrapped screens. The model was developed on the basis of a fractal model for the particle size distribution of reservoir sands. A database of sand types from the North Sea and Haltenbanken areas was established. Principal component analysis was used to reduce the number of significant variables in the database, and to provide a basis for a prediction model for critical slot widths. A series of laboratory experiments were performed, and four critical slot widths were identified for each sand type, defining a safe design interval for screen slot width. A mathematical model was developed that can be used to predict the critical slot widths for other sand types from the area. Introduction Single, wire wrapped screens with keystone shaped wire have been used to control sand production in oil and gas wells since the 1930 s. They have the advantage over prepacked screens in that they do not become plugged as easily by drilling mud. Furthermore they function as a surface filter, where the plugging material is easily removed, whereas prepacked screens are depth filters where plugging material tends to get trapped inside the prepack. Single wrapped screens do, however, have a reputation for being susceptible to plugging and/or sand production when designed according to the various traditional criteria (Refs. 1 and 2). This indicates that the design criteria for single wrapped screen completions should be revised. Sand control with screens is basically a function of the relationship between particle size and screen slot width. The pioneering work was published by Coverly (Ref. 3) in 1937. Coberly concluded that spherical particles could generally be retained when the slot width was 2.5 times the particle diameter or smaller. He also stated that in a mixture of particles of different size, the sand control properties of a screen depends on the largest particles in the mixture. He suggested that screen completions should be designed with screen slots that were 2 times wider than the d10 of the formation sand. He did not address the problem of screens becoming plugged by fines from the formation sand. This criterion has been used in California, while slot widths equal to d10 has been used on the U.S. Gulf Coast area (Ref. 4). In this paper it is shown that the design criterion suggested by Coverly, or any other criteria based on a single point on the particle size distribution curve, can not adequately describe either sand production or plugging of single wrapped screen. Instead a method is developed where a more complete description of the particle size distribution is used to predict the plugging and sand control properties of single wrapped screens. The study described in this paper has been limited to one screen type, single wrapped screens, and erosion of the screens have not been considered. An extension of the study is currently being planned that will include alternative screen designs, and also compare the susceptibility of the various screen types to erosion. Description of the particle size distribution In a traditional presentation of the results from a sieve analysis, the accumulated mass percentage of particles larger than a certain diameter is plotted on a semi-logarithmic scale. Since the particle distribution is plotted as a function of particle mass, the distribution function will emphasise the largest particles. When the purpose is to describe plugging of screen slots, it is more relevant to concentrate on the smaller particles. It is obvious that a particle matrix with zero porosity will be able to plug a screen slot completely as long as it contains particles large enough to be retained by the slot.
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- Europe > Netherlands > North Sea (0.25)
- (3 more...)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.93)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.93)
- Europe > United Kingdom > North Sea (0.89)
- (4 more...)
Abstract This paper presents the results of experiments conducted to evaluate the solubility and dissolution rate of paraffin in selected chemical solvents. The causes of formation damage from paraffin deposition and the methods used to control or mitigate the damage are discussed. A thermodynamic model using regular solution theory was developed to predict phase equlibrium of solvents and paraffin precipitation. Reasonable agreement was obtained between the model prediction and laboratory results when the solvent compositions are known. The kinetic approach to the dissolution rate suggests the use of pseudo-first order reaction form between the paraffin and the solvent. Introduction Many crude oils deposit waxy materials called paraffin during production and transportation when subjected to changes in temperature and pressure. The extent of the deposition can be manifested as damaged zones in the formation, in plugged tubing and flow lines, and in sludge deposited in tank bottoms. These paraffin-related problems cost the petroleum industry billions of dollars annually, in terms of cost of treatment chemicals, reduced production, well shut-in, inefficient use of production capacity, choking of flowlines, equipment failure, premature abandonment and increased manpower attention. Figure 1 shows a map of the United States and the states where organic deposition problems have been identified. Areas where petroleum production operations are conducted, both onshore and offshore locations, almost always manifest paraffin-related problems to one degree or another. This map illustrates the geographical extent of the problem area. The definition of paraffin (wax) problems refers to the deposit of carbonaceous material which is not soluble or dispersible by the crude oil under prevailing conditions. This carbonaceous material normally consists of high-molecular-weight paraffin hydrocarbons including either straight-chain (normal), branched or cyclic alkanes ranging from C18H38 to C70H142. They are generally very inert and resistant to attack by acids, bases and oxidizing agents. Previous research indicated that n-paraffins are predominately responsible for the deposition problem. Compounds other than n-paraffins, especially asphaltenes and resins, occluded oil and water, and possibly sand and silt, have profound effects on solubility of n-paraffins. Formation damage resulting from crystallization and deposition of paraffin within the reservoir is a recurrent production problem. The occurrence of these problems are highly dependent upon the temperature, pressure and flowing conditions near the wellbore and the reservoir crude compositions. Frequently, formation damage is caused by improper well operations such as hot oiling, non-isothermal/cold fluid injections and incompatible fluid chemistry. As fluids flow through the reservoir at pressure and temperatures below the cloud point of the fluid, precipitated paraffin particles are deposited within the pores of the reservoir. Subsequently, the absolute permeability of the region of the reservoir in which deposition has occurred is reduced, which results in a decrease in reservoir flow, mostly near the wellbore. This paper presents results of laboratory tests and analytical approaches to the evaluation of solubility and dissolution rate of paraffin in the selected commercial solvents. The research effort is to evaluate the effectiveness of these solvents for the removal of paraffin-related formation damage.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract A novel method has been developed to quantify clay swelling in aqueous solutions. In this method, a swelling clay is dispersed into an aqueous solution of desired composition, and then mounted in a special cell for X-ray diffraction (XRD) analysis. Using this method, the effects of solution pH, salinity, cation composition, temperature, fluid pressure, and overburden pressure on clay swelling can all be determined efficiently. This method uses only a small amount of sample and offers some advantages over the conventional coreflood method. It can also be used to evaluate the performance of clay stabilizers. We have determined the critical salt concentration (CSC) and critical cation ratio (e.g., Na/Ca, Na/K) for macroscopic osmotic swelling of the most common swelling clays. The information can be represented by a set of swelling diagrams in which the solution composition responsible for osmotic swelling and formation damage is delineated. The swelling diagrams can be used to determine the compatibility between shales and drilling fluids, between swelling clays and drilling filtrate or completion fluids, and between swelling clays and flooding fluids used in EOR. The effects of temperature and pressure on clay swelling have also been quantified using this method.
- Well Drilling > Formation Damage > Rock - fluid incompatibility (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (0.69)
Abstract During petrophysical and petrographical analyses of the core plugs, generally, we pay close attention to the "fines migration" when we observe kaolinite minerals filling the pore space or lining the pores. The conditions leading to a drastic reduction of permeability (formation damage), at low temperature, by kaolinite have been documented in the literature:to depend on the colloidal and hydrodynamic forces far from and near the well bore respectively and to mechanically bridge the pore throats. And, at high temperature like in steam flooding, the formation damage caused by kaolinite depends on (1) water chemistry i.e. ionic content. (2) pH of the injection water. and (3) low salt concentration. Although these mechanisms provide a general knowledge base to control the formation damage by controlling the kaolinite particles we found no clues as to what changes occur in the kaolinite morphology or mineralogy. The case in point is a Tuscaloosa sand core from central Louisiana while being drilled with a high pH fluid i.e. pH=10–12 with caustic soda. In order to understand and therefore to control the formation damage due to kaolinite migration, we subjected a series of core plugs prepared from a Tuscaloosa sand conventional core to a low temperature, high simulated spurt loss (flow rate of 11.1 cc/min) for a short period of fluid/rock contact time (45 minutes). After a thorough petrophysical analysis. we found that within this short period of contact time between the rock and fluid at pH=10-12 at low temperature, the permeability of cores decreased considerably. The petrographical analysis of the same cores revealed that the reason for this drastic change in permeability was the onset of the conversion of kaolinite to halloysite and dickite under the oxidative effects of Sodium Peroxide. Also, the amphoteric nature of kaolinite similar to Al(OH)3 i.e. dissolution of kaolinite in both acids and bases, plays an important role in its solubility in caustic soda at pH=10-12. On the basis of our findings we concluded that in both field and laboratory coring and/or drilling the Tuscaloosa sand or possibly any other sand with a high kaolinite content (greater than 5%) the best conditions for controlling the formation damage are to keep the pH of all injection fluids in a buffered and well controlled state of near neutral and/or to control the filtrate to near zero in such sensitive formation. Introduction Most, if not all, laboratory analysts, upon observing kaolinite mineral in the pore space of the side wall or conventional cores, conclude that the main cause of a possible formation damage (decrease in permeability) could be attributed to the migration of "fines" within the pores or pore throats. Pursuing the matters further, the analysts conduct a series of core flow tests in order to document the magnitude of damage to permeability and other visual observations. One of these visual examinations. in the case of a "caustic flooding" project encompassing a comprehensive laboratory and field work, reported some white particles looking like kaolinite plugged some Berea cores in the lab tests. The Berea cores contained about seven percent kaolinite clay. Also, the same kind of whitish fine material showed up in the surface facilities in the field and was believed to be kaolinite plugging the gravel pack and the screen. Although the process of steam flooding (Huff and Puff) was successful in the field, the parties involved did not get a chance to examine thoroughly the "whitish fines" showing up in the surface facilities of the caustic-steam flooded well drilled near the above mentioned well. In short, if there was any problem with the caustic flooding in terms of fines migration and/or formation damage, neither was it understood nor remedied.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Pore and Throat Network Model and Its Application to the Optimal Selection of Temporary Plugging Particles
Wenrong, Mei (Southwest Petroleum Institute) | Shihong, Shu (Southwest Petroleum Institute) | Tianhua, Lai (Southwest Petroleum Institute) | Wenzhong, Liu (Sichuan Petroleum Administration) | Guoheng, Hu (Tuha Oilfield)
Abstract To a great extent, experiment selection of temporary plugging particles(TPP) in the temporary plugging techniques (TPT) is blind at present. Based on the investigation of particle migration, deposition and plugging mechanism in the porous media, network model, the inter-connected pore and throat network on the basis of reservoir pore structure, is applied to the optimization of TPP in the TPT. It is shown that the result of simulation has a good agreement with that of core fiooding experiment and can be used to guide the study of core flooding experiments. The main advantages of this method are:the model can be repeatedly used many times and can be used in the simulations of various purposes and aspects; the results are highly comparable by the simulation while much less by the core flooding experiments. Introduction It's well known that formation damage existing extensively in each phase of field operations is a difficult problem in the petroleum industry, and can not only damage oil and gas resources and considerably reduce the productivity of hydrocarbon reservoirs, but also even kill hydrocarbon reservoirs, and therefore cause a very great waste of manpower, material and financial resources. During the past several decades, beginning with our original consciousness of formation damage problem, unremitting efforts and a great number of researches have been made from the understanding of formation damage mechanism in the past to the controlling and preventing of formation damage by using various methods at present.
- North America > United States (0.69)
- Asia > China (0.47)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tuha Field (0.99)
- Asia > China > Xiaermen Field (0.99)
Abstract Artificial neuron network (ANN) models are designed to emulate human information processing capabilities such as knowledge processing, speech, prediction and control. The ability of ANN systems to spontaneously learn from examples, reason over inexact and fuzzy data, and provide adequate responses to new information not previously seen, has generated increasing acceptance for this technology in the engineering field and resulted in numerous applications. A preliminary investigation into the use of this novel technology is presented towards predicting formation damage by quantifying wettability and two-phase relative permeability of oil reservoirs. An artificial neuron network model based on the Back Propagation technique is trained with a number of variables from experimentally established relative permeability (relperm) curves. The reservoir core input data covers an extensive range of porosities and permeabilities from different lithologies having diverse wettabilities. The trained model is then tested with only a couple of easily obtainable input variables such as the Swc and Sor and predictions are made on the wettability and relperm curves. A change or shift in the relperm curves is associated with changes in wettability, and perhaps to formation damage in the drilling process. The wettabilities of the rock-fluid system are predicted to within 90% of the experimentally determined values. The relperm curves, particularly the end-points are predicted to within 85% of the measured results. The accuracy of the predictions are significantly enhanced with model training using more precise reservoir data and better defined formation lithologies. Neural networks have immense potential in predicting relperm curves and thereby assessing formation damage in reservoirs. Introduction Formation damage is usually associated with the decrease in permeability of hydrocarbon reservoirs. The resulting permeability changes directly influence the relative permeabilities of the hydrocarbons in-place. The important reservoir parameter, wettability, may also be altered, depending on the type and cause of formation damage. Drilling and completion fluids, and additives, are known to alter wettability around the wellbore, due to improper fluid and/or additives selection. Accurate prediction of the wettability and the relative permeabilities at any instant will therefore provide a valuable tool for formation assessment and the ensuring changes due to possible formation damage.
- Geology > Rock Type (0.76)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.54)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)