Sweet Wells Research Articles

Iron Control in West Texas Sour-Gas Wells Provides Sustained Production Increases

Summary Permian Basin operators have recorded sustained production increases bypreventing production increases by preventing precipitation of iron sulfide andother precipitation of iron sulfide and other sulfur-containing species. Thisimprovement has resulted largely from cleaning out tubing before acidizing andfrom preventing the precipitation of ferrous sulfide and the formation ofelemental sulfur by simultaneous use of iron chelants and sulfide-controlagents. Previously used methods gave only temporary production increases thatterminated production increases that terminated when iron dissolved by thestimulation acid reprecipitated in the pay zone and damaged the formation afterthe stimulation acid was spent. This paper describes a method to optimize ironsulfide control, methods to minimize reprecipitation. and case histories fromthe Permian Basin that show improved methods to control iron in sour-wellenvironments. Introduction Stimulating wells with acid was first reported in 1896. Acid was proposed tobe injected into the formation to dissolve the rock and to improve the flow ofoil to the wellbore area. This method offered advantages over the then currentstimulation method of "shooting" the well. Although the use of an aggressive fluid, HCl, offers many advantages thathave resulted in its widespread use, it does have several disadvantages. Thispaper discusses the disadvantage of the high solubility of iron containingcompounds in HCl: the iron dissolved from the tubulars by the stimulation acidcan be redeposited as a precipitate in the pay zone, damaging the formationwhen the HCl is consumed. Formation damage in sweet wells occurs when ferric ion is precipitated fromsolution. The iron compounds dissolved during an acid treatment in sweet wellscan place both ferric ion (Fe) and ferrous ion (Fe) in solution. The formationis damaged because the pH of spent acid is about 4.0 and the solubility offerric ion is very high in fluids with pH values below 2.5 and very low influids with pH values above about 3.5. (The values between 2.5 and 3.5 willhold some iron in solution, but to a lesser extent.) Ferrous ion does not causeproblems in sweet wells because its precipitation does not occur until a pH ofabout 7.0 is reached. In recent years, several methods have been used successfully to control ironreprecipitation in sweet wells. Some common methods include the use ofbuffering agents to hold the pH of the fluid below 2.5, chelating agents toreact with the ferric ion to provide soluble complexes, reducing agents toprovide soluble complexes, reducing agents to modify the oxidation state offerric ion, and combinations of these methods. These systems have found utilitywhen acidizing fluids are applied to sweet wells where ferric ion has beendissolved, but the reprecipitation problem is not fully remedied if sulfidesare present. This results because the buffering systems, some chelating agents, and reducing agents fail to prevent reprecipitation of iron with H S to formiron sulfide and, in some cases, elemental sulfur. Damage From Scale Iron sulfide reprecipitation in the formation (from spent-acid solution) isthe most probable reason that acid jobs fail to achieve probable reason thatacid jobs fail to achieve sustained production in sour producing wells orincreased injectivity in injection wells that carry sulfides. The primarysource of the reprecipitated iron sulfide is iron containing sulfide scalesdissolved from the tubulars by the acidizing fluid. Wells that produce or inject sulfidecontaining fluids contain iron sulfidescales or iron sulfide corrosion products. The type of iron sulfide depositeddepends on a number of considerations, including temperature, brine salinity, and the presence of other gases, such as CO2. Mackinawite (Fe S), troilite(FeS), or pyrrhotite (Fe S) is almost always found on tubular surfaces. Pyrite(FeS) and marcasite (FeS) are also Pyrite (FeS) and marcasite (FeS) are alsofrequently found. Another complication is that one or more types of ironsulfide will precipitate and undergo further reaction with precipitate andundergo further reaction with either H S or the iron surface to create layersof different compositions of iron sulfide. Each compound has its own specificsolubility. The general trend is that compounds with approximately one-to-onestoichiometry will be readily soluble and have rapid reaction rates with HCl, while compounds with higher sulfur stoichiometries will have lower solubilityand much slower reaction rates (Table 1). It is a mistake to assume that wellscontaining moderate to small amounts of H S will form less scale or corrosionproduct on the tubulars than wells with higher H S concentrations. What isknown is that most of these sulfide scales are soluble to some degree in acidicstimulation fluids. These scales or corrosion products can be redeposited inthe formation, products can be redeposited in the formation, causingdamage. The magnitude of the problem is often not recognized. Iron sulfide scalescan react with HCl to an extent that effectively reduces the acid concentrationto less than 1% HCl content. These fluids, which are high in ferrous iron and HS content, will further spend when contacted with the formation containingcalcium carbonate or other acid-consuming species. JPT P. 603

Iron Control Provides Sustained Production Increase In Wells Containing Sour Gas

Abstract Acid stimulation of wells containing hydrogen sulphide has in some cases resulted in short-lived production increases. The rapid decline in production has been thought to be related to reprecipitation of sulphur-containing species which reduce the flow of hydrocarbons when the well is placed on production. By using agents which interact with both iron ions in solution and hydrogen sulphide, precipitation of iron sulphide and elemental sulphur can be controlled and damage to the formation permeability can be reduced. The result of proper control of these sulphur-containing species is to provide the operator with sustained production increases after acidizing. This paper will discuss the mechanisms of damage, current iron control methods, solutions to the deficiencies 0f the currently used methods, and case histories showing use of improved methods of iron control in hydrogen sulphide environments. Introduction The use of acid to improve the production of hydrocarbons from subterranean formations as an effective method of stimulation was introduced in 1896(1). In these processes, acid was injected into the formation to dissolve the rock matrix to improve the now of hydrocarbons from the formation to the wellbore area for removal. Hydrochloric acid (HCl), an aggressive fluid, has many advantages which have resulted in its common use as a stimulation fluid. However, as such, an aggressive fluid does have some disadvantages. The major disadvantage pertinent to this paper is the high solubility in HCl solutions of iron containing minerals, many of which will reprecipitate when the acid content of the fluid decreases(2). Several methods have been used with success in controlling the repredpitation of iron in sweet wells. Some more commonly used materials have included buffering agents, chelating agents, reducing agents, and combinations of the above systems, These systems are designed to control the reprecipitation of ferric ions as hydrated ferric oxides. 'This ion has great solubility in fluids with pH values lower than about 2.5, but rapidly becomes insoluble in fluids with pH values above 2.5(3). This problem occurs because the normal pH of a spent acid fluid is about 4.0. Buffering agents can maintain a high acid content of the spent acid fluid at pH values below 2.5 for some time, and when used with chelating agents, have allowed spent acid fluids to retain high concentrations of ferric ion in solution(4,5). Reducing agents chemically convert ferric ion to ferrous ion(6,7,8). Ferrous ion does not precipitate at the pH of spent acid fluid. These systems have been shown to be effective in sweet wells; however, the problem becomes severe when sulphides are present. 'This is due to the failure of buffering systems, reducing agents, and some chelating agents to prevent the reprecipitation and reaction of iron solution species with hydrogen sulphide. Scale Sources The major source of possible damage to sour gas wells after acidizing is the reprecipitation of iron sulphide in the formation from the spent acid fluid. The source of this compound is from the redissolution, by the stimulation acid, of existing iron-containing sulphides on the tubular(9).

Evaluation of Seal Materials for High-Temperature H2S Service

Abstract The drilling of deeper wells in the exploration for oil and gas has imposed new demands on seal materials used in the completion of these wells. Materials used in the past for the completion of shallow sweet wells well not perform satisfactorily in the deep sour hot environment. These materials undergo serious chemical and physical degration under the conditions imposed by these wells. Seal materials have been tested in the laboratory at various temperatures, from 200 to 450 °F, in 35% H °S, 15% CO2 50% CH4 and pressures from 1,000 to 15,000 psi. The materials have been used in actual field conditions with temperatures up to 425 °F and an 8,000-10,000psi differential across the seals. This paper describes the laboratory evaluation of these materials and the field tests used to develop reliable seals for the harsh environment. Introduction The first well in the Thomasville field, near Piney Woods, Mississippi, was completed with a conventional packer having a sliding-seal assembly set deep in the well. After the production test, it was found that the elastomers in the packer, tubing hanger and valve stem packing had failed. Extensive research revealed that no currently available elastomer could withstand the environment of hot, high-pressure, sour gas for any appreciable period of time. Consequently, well configurations were altered to aboid the use of elastomer seals in the well(1). Research and development of polymeric seal materials at Otis Engineering has resulted in a significant development for oil and gas completions. Laboratory tests were designed to simulate as near as possible the condition encountered in a downhole situation. Sour gas mixtures were specified to contain 35%, H2S (hydrogen sulphide), 15% CO2, (carbon dioxide) and 50% CH4, (methane). Sour crude was obtained and kept under pressure for use in elevated~temperature evaluations. The existing materials were pushed as far as possible in temperature (450 °F) and pressure (15,000 psi) to determine if any were suitable for the severe conditions. The commonly used oil seals were found to undergo serious physical and chemical deterioration. The specific objectives of the test program were:to evaluate various elastomers and thermoplastic materials to determine which were the most resistant to hot, sour gas and fluid conditions;to determine if a combination of materials would perform better than anyone material alone; andto field test qualified materials under the most severe conditions available. Laboratory Tests The environment used in the test program consisted of a gas mixture containing 35% hydrogen sulphide, 15% carbon dioxide and 50% methane. The sour crude contained approximately the same composition as the gas, As the test fixture was charged with gas, a liquid phase of fresh water and diesel oil was also introduced, because it was assumed that these are produced in the formation. The lest chamber (Fig. 1) is made of C-75 and Inconel material for H2S testings. This fixture is heated by an oil bath with careful control of the desired temperature. The major portion of the testing was conducted in a static condition.