Organic skin damage in oil producing wells is a major factor in the loss of productivity and revenue. Paraffin and asphaltene deposition in the formation and around the well bore creates a barrier for the transportation of the crude oil to the tubing. Many producing wells have experienced a production decline that can not be explained by reservoir depletion. Organic damage may occur naturally or through various intervention practices used in the oilfield. An increased awareness of the potential for ongoing organic damage has been developing slowly over time. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection and application methods are discussed. Numerous case histories for a variety of problems are also presented. Introduction Two naturally occurring components of crude oil are paraffins and asphaltenes. Paraffins are composed of carbon and hydrogen atoms with a carbonchain length starting at C18–20 up to C70 or higher. Though paraffins are usually straight-chained hydrocarbons, they can also contain a variety of branched alkyl or cyclic groups. Asphaltenes are heterocyclic unsaturated macromolecules consisting primarily of carbon, hydrogen, and minor components such as sulfur, oxygen, nitrogen and various heavy metals. These higher molecular weight components of crude oil are inequilibrium at "normal" reservoir condition. As crude oil is produced thisequilibrium is upset by a number of factors such as the following: temperature declines, pressure reductions, addition of miscible gases and liquids, acidizing, hot oiling and other oilfield operations. The primary mechanism for paraffin deposition is thermal cooling. Decreases in temperature promote paraffin deposition. The key mechanisms for asphaltene deposition are the decrease in pressure and the introduction of incompatible fluids.1,2,3 Problem Identification In order to remediate the damage it is first necessary to identify thesource of the problem. The first step in this process is a thorough systems analysis. Critical information necessary at this stage consists of the following: production history, current production rates of oil, gas and water, drive type, well depth, temperature and pressure profile, well configuration, fluid level, EOR technique, stimulation and maintenance history. The second step in the process is laboratory testing on samples of crude oil, water and solid deposits. The crude oil is characterized by wet chemical and instrumental analysis for % paraffin, % asphaltenes, % asphaltic resins, %aromatic and % saturates. A cloud point, pour point, gas chromatograph andviscosity profiles are also run. A series of specialized deposition/instability tests are run to investigate the potential for deposition. For paraffinic crudes these consist of paraffin deposition tests using cold fingers or other thermal deposition devices. The potential for asphaltene deposition is studied by conducting depressurization studies on live oils to determine the asphaltene flocculation point. For surface samples of crude oil a variety of asphaltenein stability tests are conducted. These consist of flocculation point determinations using a variety of anti-solvent titration and measurement techniques. Solid samples are analyzed using similar wet and instrumental techniques. Water samples are analyzed for elemental composition and scaling tendencies are determined. From the information gathered using these various tests, the source and magnitude of the problem can be identified. Primary, secondary and even tertiary problem sources can be identified as drivers for formation damage.

Formation damage caused by the precipitation and deposition of paraffin or asphaitene particles has been a recurrent problem in the production of crude oil. A number of well established oilfield operations have been found to aggravate these organic deposition problems. Laboratory testing of crudes and chemical additives has led to a number of solutions to these problems. Case history information on testing, chemical application, and subsequent field results are presented.

Summary In the surface transportation of crude oils, high flow line pressures are encountered for a number of reasons. Basically these are a function of the rheological and depositional properties of the crude oil under the temperature-profile and shear-rate conditions developed in the system. These problems can be categorized into these areas: paraffin deposition, asphaltene deposition, thixotropic crude oil, turbulent flow transmission, and low-gravity asphaltic-based crude oils. Various laboratory and field tests are used to identify the key features of these problem crudes for identification and chemical treatment purposes. Introduction Pressure problems during the production of crude oil result in considerable trouble and expense to the producer. Ten years' investigation has resulted in substantial progress in identification and chemical treatment of these problem areas. Proper identification of the mechanism causing the pressure increase has resulted in the elimination of many mechanical and chemical misapplications. The net result has been a reduction in costs to operate these problem systems. Each problem area has key features differentiating it from the other causes of high pressures. The tests used to identify these key factors include cloud point, pour point, viscosity, yield value, solubility parameters, pumping studies, and various deposition and removal tests. Comparative testing of chemical additives under simulated field conditions yields valuable data on the relative treating efficiency of various chemical structures. Subsequent field trials clearly demonstrated the value of preliminary laboratory and onsite testing prior to chemical applications. Paraffin Deposition Paraffin deposits consist of a mixture of linear and branched chained hydrocarbons in the range Of C 18 H 38 to C60 H122, generally mixed with other organic and inorganic materials such as crude oil, gums, resins, asphaltic material, salt, sand, and water. The accumulation of paraffin waxes on pipewalls leads to constriction, which effectively reduces the useful diameter of the line. This causes an increase in pumping pressure and/or a decrease in volume throughput. The solubility of paraffin in crude oil depends on the chemical composition of the crude, temperature, and pressure. Paraffin precipitates from the crude oil at an equilibrium temperature and pressure defined as the cloud point. Paraffin deposition takes place by three mechanisms that transport both dissolved and precipitated waxy crystals laterally. When the oil is cooled, a concentration gradient leads to the transport, precipitation, and deposition of wax at the wall by molecular diffusion. Additionally, small particles of previously precipitated wax can be transported laterally by Brownian diffusion and shear dispersion. Wax Deposition Equipment. Paraffin deposition equipment has been described by a number of authors. All make use of a deposition surface cooled under controlled conditions to a temperature below the cloud point and crude oil solution temperature. We use two types of deposition equipment. The first method is a "static cold finger" similar to that outlined by Jorda. This method allows control over the variables of oil-solution temperature, deposition surface, temperature, temperature differential, T, and time. A second method is a "rotating disk apparatus," as described by Eaton and Weeter, which also controls the velocity variable. Fig. 1 is a diagram of the apparatus. This unit consists of four probes, each of which can be set electronically for a specific temperature. Work has been conducted on a variety of synthetically prepared crude oils and stabilized field crude samples. Paraffin Inhibitors. Paraffin inhibitors are polymers capable of crystal distortion or modification during the deposition process. Because of this cocrystallization mechanism, it is necessary to have the chemical in solution above the cloud-point temperature. This prevents or interferes with the molecular diffusion mechanism of deposition. It also modifies the crystal structure of waxes precipitated into small, highly branched structures with low cohesive properties. Three popular crystal modifiers are copolymers in these groups:Group A-copolymer of ethylene vinyl acetate,Group B-copolymer of C18 through C22 methacrylates, andGroup C-copolymer of olefin/maleic anhydride esters. Laboratory Deposition Testing With Rotating Disk Apparatus. A yellow Wasatch crude oil from the Altamont, UT, area was tested for paraffin inhibition. This crude had a pour point of 38 degrees C [100 degrees F] and a cloud point of 66 degrees C [151 degrees F]. Test conditions are shown in Table 1. Additives 1 and 2, both in Group C, were the most active paraffin inhibitors on this crude. JPT P. 779^

Paraffin inhibitors can have a significant impact on crude oil production for some developments. Paraffin inhibitors are used for reducing wax deposition in flowlines and/or for improving the flow properties of waxy crude oils. The effectiveness of the paraffin treatment is dependent on the crude oil chemical composition, inhibitor chemistry, inhibitor dose rate, and the production conditions. The available choices of paraffin inhibitor formulations for a particular application are, however, often fixed by constraints related to delivery or injection of the product. For example, products for deepwater subsea umbilical injection must remain fluid and solids-free at all conditions of temperatures and pressures the products experience in their respective injection paths - from the storage tanks all the way through the umbilical and (if present) capillary injection lines. This paper details the challenges associated with the delivery of paraffin inhibitor chemicals for deepwater offshore developments. The stability of paraffin inhibitor formulations depends on both pressure and temperature. Umbilical and capillary line failure is a major concern in the oil industry. Best practices to qualify products for umbilical and capillary injection have been rapidly evolving over the last 10 years. Recently high-pressure viscometry has been found to be beneficial for product qualification. In particular, high pressure viscosity measurements have proven to be invaluable for determining whether pressure related stability concerns may exist in formulations at cold deepwater temperatures. Instability in the polymer solution phase behavior of paraffin inhibitor formulations at high pressures and cold temperatures may be the reason behind some industry umbilical line failures. Also discussed are contrasts between deepwater applications in subsea umbilical lines and in DVA dry-tree capillary lines as the constraints on the paraffin inhibitor can be very different. Four recent case histories of different types of deepwater paraffin inhibitor applications are presented: two subsea umbilical applications, one DVA capillary application, and one application for a well test. The case histories discuss how the paraffin inhibitor applications fit into the overall wax strategy for the projects, constraints placed on the products by the injection conditions, and performance of the products.

Summary Wax deposition on downhole equipment and in chokes, flowlines, separators, dehydration and storage equipment is a costly problem in the northern Michigan area called the Niagaran Reef trend. A number of mechanical removal techniques have been used to treat for paraffin. Among these are paraffin cutters, plunger lift, rod scrapers, hot oil or water, plastic coatings, and flowline pigging. Improvements in chemical formulation, testing, and applications have resulted in a number of economically successful chemical programs for paraffin control. Examples of field problems and solutions are presented. Introduction The northern Michigan Niagaran Reef trend consists of a belt approximately 64 km [40 miles] wide extending across the northern part of the state from Ludington in the west to Alpena in the east (Fig. 1). Crude oil is produced from an average depth of 1640 m [5,380 ft] from produced from an average depth of 1640 m [5,380 ft] from the Silurian Niagaran formation. Initial field development began in the late 1960's. Since that time, paraffin-related problems have been a major expense for the producer. problems have been a major expense for the producer. Paraffin problems vary in severity from daily for some Paraffin problems vary in severity from daily for some wells to monthly for other wells. The production of-high-total- dissolved-solids (TDS) produced waters in the range of 100,000 to 400,000 ppm aggravates the paraffin deposition problems, Salt blocks are prevented ppm aggravates the paraffin deposition problems, Salt blocks are prevented through the use of continuous injection freshwater systems or periodic batching to reduce brine weight from 5.0 kg [11.0 periodic batching to reduce brine weight from 5.0 kg [11.0 lbm] down to an average of 4.3 kg [9.5 lbm]. Paraffin-deposition problems occur throughout the production system. Major problems exist with deposition in production system. Major problems exist with deposition in the tubing string, chokes, flowlines, and separators. A wide variety of mechanical, thermal, and chemical methods have been used to control the deposition of wax. Paraffin cutters, mechanical rod scrapers, plastic coatings, Paraffin cutters, mechanical rod scrapers, plastic coatings, flowline pigs, hot oil and water, paraffin solvents, diesel, surfactants, and crystal modifiers have all been used with various levels of economic success. In recent years, improvements in treating efficiency have made a number of chemical treating programs more cost efficient than standard thermal and mechanical methods. A combination of chemical treatments with occasional mechanical/thermal methods has also provided good overall performance. The key to successful chemical treating is a combination of chemical choice and application technique to solve specific field problems. Theory Paraffin Deposition. Typical paraffin deposits are a Paraffin Deposition. Typical paraffin deposits are a mixture of linear and branched-chain hydrocarbons (C 18 H 38 to C70H 142) combined with a wide variety of organic and inorganic materials that add bulk to the deposit. These deposits vary in consistency from a mushy liquid to a firm, hard solid, depending primarily on the amount of oil present. present. Paraffin deposition takes place by three mechanisms that transport both dissolved and precipitated wax crystals laterally. As the oil cools, a temperature gradient is established that leads to the transport and deposition of wax on the colder pipewall by molecular diffusion. Particles of previously precipitated wax crystals carried in the oil are transported laterally by Brownian diffusion and shear dispersion. The cloud point of a crude oil is defined by ASTM as that temperature at which paraffin particles first begin to precipitate from solution. Paraffin deposition can take place only on surfaces below this critical cloud-point place only on surfaces below this critical cloud-point temperature and that of the bulk crude OH. Paraffinic crude oils behave as Newtonian fluids at temperatures above their cloud point. Thixotropic characteristics begin to appear at just below the cloud point of the crude because of precipitated wax crystals and become pronounced as the pour-point or solidification temperature is reached. Paraffin-deposition testing has been conducted by number of authors. Paraffin-deposition testing has been conducted by number of authors. Generally the wax is deposited on a surface referred to as a "cold spot. "When the temperature differential, percent wax, shear rate, or deposition surface material is varied, a number of deposition trends can be analyzed. Testing chemical structures has led to the identification of a number of paraffin inhibitors that provide crystal distortion and reduce paraffin deposition. These compounds are generally added continuously to the crude oil above the cloud-point temperatures. As the crude cools, these inhibitors cocrystallize with the precipitating wax and cause a crystal distortion to take place. The resulting crystals are small, highly branched, dense crystals with greatly reduced agglomeration properties. Crystal modification chemicals are polymers with molecular weights ranging from 1,500 to 100,000. Because of their molecular weight and structure, these chemicals are difficult to use in low winter-time temperatures. SPEPE P. 213