Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location. The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential. This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance. Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.

Hydraulic fracturing is a widely used technology in the industry to enhance oil and gas production, particularly in tight formations. Tight gas and shale cannot sustain commercial production rates without fracturing. Although the technique has been used in the industry for many years and vast improvements have been made in upgrading fluid chemistry, proppant types, pump schedule sequence, and overall well completion system, a close evaluation is always required to ascertain that the fracturing has provided the level of productivity expected from the candidate well. Such evaluation and analysis will help improve and optimize the stimulation technique for any given reservoir and field conditions, address specific challenges in that area, and determine remedial plans on any well that did not show expected results in terms of productivity enhancement. Saudi Arabian gas wells are usually stimulated to enhance and sustain production. Wells drilled in the R-1 reservoir in Field-A, that exhibit low to moderate permeability, are routinely hydraulically fractured. Many of these wells produce a high, sustained rate after a successful stimulation treatment. Some others do not perform up to expectation as seen from the rate decline. This can be caused mainly by inefficient fracture treatments such as achieving short half-length, limited vertical coverage, and poor post-frac cleanup. A critical and intense work on numerous wells has been performed using available data from geology, open hole logs, cores, pressure transient tests, etc., to understand and quantify reservoir characteristics, fracture properties, and flow capacity of these wells to come up with plans to improve productivity. Such plans include remedial treatments such as refracturing, placing additional perforations in previous unperforated intervals, initiating hydraulic fractures in different layers, and sidetracking the well to change its trajectory and geometry to contact new producing intervals. This paper summarizes the well conditions, complete evaluation processes, and suggests remedial procedures for each well to ensure full potential.

This paper describes the application of a new numerical model to simulate any work over plans in order to assess the work over efficiency and the well productivity enhancement, prior to operations commencement. A case study is discussed, where an operator in Egypt had a plan to improve the productivity of an oil well producing from a multi-layer reservoir, where a low productivity layer had been previously identified and characterized by multiple techniques. It was critical for the operator to enhance the productivity across this layer and to identify the appropriate remedial action (water shut off, re-perforate, or stimulation) that could impact the whole field production performance. The operator had decided to re-perforate and add new perforations to the low productivity layer. The numerical simulation model was hence applied to assess work over techniques and to determine the most suitable remedial action for implementation. The simulation result of reperforation and adding new perforations showed water cut drop by 6% with an increase in oil rate by 538 b/d and in water rate by 348 b/d compared to the initial profile identified by production logging. The result of the numerical simulation model suggests that the low productivity layer should be considered as a candidate for stimulation (fracturing/acidizing). When the operator attempted to re-perforate the low productivity layer, the production performance after the re-perforation did not show a major improvement, as the water cut decreased by 6% only with a small gain in oil rate, which is in agreement with the simulation model outcome. The operator understood the reason for the field wide low productivity from this layer and hence obtained a key to unlocking the reserves contained in this layer across the whole field in future field development plans.

GASCO operates two NGL plants located in Alexandria; Amerya LPG plant and Western Desert Gas Complex (WDGC). The Amerya LPG plant receives & treats 300 MMSCFD of western desert gases from Badr 2,3 (Bapetco), Abu-Sanan, south dabah, petro-alm, (neag & sheba), west setra and septco fields, to produce 250 MT/Y LPG for local market and 25 MT/Y condensate to use for the refineries and the other is WDGC plant receives & treats 600 MMSCFD of western desert gases from Al-Obayed (Bapetco), Salam, Tarek and El-Qaser (Khalda) fields, to produce 465 MT/Y of Ethane/Propane mixture used as a feed stock for petrochemical industry (SIDPEC Company) to produce Ethylene and 280 MT/Y & 59 MT/Y of LPG and condensate for the local market consumption adding value for national economy by reducing the imported quantities of the same products and 210 MT/Y of Commercial Propane for export to the international market increasing income from the hard currency to support the national economy. Recently, GASCO has started up a new project to receive & treat extra 300 MMSCFD and also to integrate the two plants to maximize Ethane and Propane productivity. The project design is based on adding new process facilities in Amerya plant to start producing C2+ that directed to WDGC, while a new train is added in WDGC to increase the feed gas capacity and maximize C2+ recovery by applying the Gas Subcooled Process (GSP) as Ethan mode of operation scheme. This paper presents a study to increase the productivity of the two plants by using simulation software applied on field to help the decision making for what the optimum conditions should be applied in different modes of operation to increase the production.

An oil well with two perforated zones had an initial production rate of ~2,400 BOPD with water traces. Within 3 months, production decreased to ~1,000 BOPD and water cut increased to >25%. It was critical to identify the cause of decreasing productivity and increasing water cut to plan for remedial action. The reservoir was evaluated by integrating several answers obtained from reservoir saturation characterization through use of pulsed neutron capture and water-flow log data, as well as from conventional and advanced production logging. Production logging showed that water was sourced from the lower perforated interval, while only a small proportion of the flow came from the upper reservoir layer. Pulsed neutron logging confirmed a high amount of depletion in the zone below the lower perforation, with oil remaining in the upper part of the lower perforated zone and in the upper perforated zone. Bypassed oil was also found below the water-producing zone, confined between the oil/water contact and a thin shale break. This shale break is a major permeability barrier and allows lateral water movement through the high-permeability lower zone. A multilayer test carried out with production logging tools showed that the productivity index of the upper zone was only one-tenth that in the lower zone, due to either intrinsically low permeability or high skin factor. The multilayer testing also showed that of the two comingled layers, the upper layer had approximately one hundredth the permeability of the lower layer. Reperforation of the upper zone resulted in only minor improvement in well production, thus confirming that the low productivity was not caused by high skin factor, but was due to low permeability. From the testing, it is clear that to produce the oil from the upper zone, it will be necessary to produce the two zones separately, with different drawdown. Since similar conclusions were obtained in other wells in the field, these results provide a fieldwide strategy for improving field productivity.

Much has been written about carbonate reservoir complexities, heterogeneity, and data integration at different scales. However, there are not many published examples that show a comparison of producibility modeling predictions and actual field results that include data from core, advanced openhole well logs, formation testers, and drillstem tests. In this study, we present the integration of data and measurements from advanced technologies to evaluate reservoir heterogeneity of carbonate formations on multiple scales. Quantitative textural analyses based on a comprehensive suite of petrophysical logging measurements were integrated with core data and formation testing data to characterize hydrocarbon/water transition zones and formation permeability and producibility. The offshore carbonate reservoir studied is composed of limestones and dolomites. Despite the inherent chemical complexities and hidden modes of origin, dolomites often exhibit favorable reservoir quality with high porosity and permeability properties. For this reason, E&P companies continue to predict where drilling targets are most likely to encounter these sweet spots. Traditional permeability correlations are not effective in these systems, leading to overdependence on porosity-based reservoir descriptions to predict fluid flow. Using nonparametric regression, we have established a relationship between permeability and porosity from logs that are available fieldwide. Subsequent integration of this data with interval pressure transient test data in zones selected based on the observed rock heterogeneity enables further optimization of the final permeability correlation. The descriptions of the field examples confirm the success of this integrated approach and include the planning, real-time monitoring, and final validation of permeability and anisotropy at different scale during the exploration phase of a field. Selecting the well locations for development using the proposed approach has proved valuable for improving field development practices. The results have led to enhanced reservoir characterization based on flow (permeability) and storage-capacity analyses (porosity partitioning), and a better understanding of the reservoir heterogeneity at different scales; the results have been used to improve drillstem test designs and reservoir production strategies.

The West Qarun development concession is located in the Abu Gharadig basin of the Western Desert, approximately 200 km SW of Cairo City. The block comprises a gross area of 46.2 km2 and contains the producing West Qarun oil field. Oil production commenced in October 1994 from four wells with initial production rate 1200 BOPD. The field showed constant production for the last ten years before SOG acquired the concession at a level of ±500 BOPD. The cumulative oil production amounted to 6 MMSTB of 40 deg API non-sulfurous, slightly low gas-oil-ratio paraffinic crude mainly from the Abu Roash ‘G’ and Upper Bahariya reservoirs through fifteen wells. SOG after acquiring the concession, in 2009, conducted 3D seismic survey in order to reveal the uncertainties concerning field structure and its interpretation opened new chances by indicating higher OOIP and new promising locations for drilling. The results of new drilled wells WQ-7, WQ-9, and WQ-10 proved the new interpretation and gave more confidence in the resulted figures. The Abu Roash "G" producing sands are characterized by formation tightness. So applying of hydraulic fracturing technique to enhance the existing wells productivity showed excellent results. Also tight formations need large shut-in time to obtain accurate pressure measurements. Therefore a pilot test was conducted to study the effect of shut-in time on the pressure measurements which will be illustrated thereafter. Based on the studies, a complete development plan was prepared and the application of the first stage resulted in increasing the production five times (from 500 to 2500 BOPD) and tripling the proven remaining reserves as well (from 6.3 MMSTB to 19.5 MMSTB). This paper will illustrate the approaches applied for the rejuvenation of West Qarun field and emphasizes the role of reservoir characterization and reservoir management in maximizing the field value.

After several discoveries of oil and gas in fractured basement reservoir such as White Tiger, Dragon, Aurora and Ruby in 1990s, the basement on the continental shelf of Vietnam has become a major target for domestic and foreign oil companies. Oil produced from basement is accounted for more than 90% of the total produced oil. Due to lesser and lesser new discoveries and most of the big oil fields are in declining phase, the Improved Oil Recovery (IOR) methods are bringing advanced technological solutions to boost oil recovery from mature fields, geologically complex low permeable and fractured reservoirs in the future. Among the IOR techniques, horizontal wells appeared to be a promising one in both short and long term of reservoir life. Horizontal well (HW) has a higher productivity and pay contact as increase the length of well, thereby reducing the number of wells required to drain the reservoir. In the case study presented, the efficiency of horizontal well will be evaluated by analyzing horizontal well performance. Both analytical and numerical solutions will be investigated. A 3D numerical model of the South-East Dragon field was set up with five production wells and one injection well that is known as a base case. Then running base case is to find the appropriate places for putting new well. Ten interesting scenarios are presented in this paper where the horizontal well is analysised both HW location sensitivities and HW length sensitivities. In addition, this research described a step-by-step procedure that can be used when performing an economic analysis of a horizontal well project. The results from the case study indicate that a combination of factors including total economic, analytical and numerical simulation is required to optimum horizontal well length in the fractured basement reservoir of South-East Dragon oil field in Viet Nam.

Oil and gas exploration in carbonate reservoirs typically utilize conventional techniques in perforation, matrix acidizing stimulation and well testing. Currently, oil companies have moved to more marginal reservoir targets. Application of these techniques has often yielded disappointing results and tighter zones are often abandoned for more promising target intervals. With increases in oil and gas production targets, operators are being forced to investigate more marginal reservoir layers for reserves and production potential. The real challenge facing oil industry today is that successful exploration requires a change in drilling, completion and stimulation techniques currently utilized by operators. Marginal reservoirs can have lots of resource potential and reserves, but may require horizontal well drilling, and/or multiple stage hydraulic fracturing to achieve economic production targets. This type of strategy is more expensive than conventional method(s) and is proven in some circles as potentially risky and many of these risks must be addressed and mitigated. In an effort to reduce risks and costs associated with the exploration process, a new stimulation strategy has been adopted for tight intervals to explore and appraise these intervals using vertical wells prior to going to horizontal wells. This paper presents and analyzes oil exploration well case study in which a new strategy has been applied and evaluated. The study also demonstrates that this approach can lead to new resource discoveries, better reservoir understanding and improved well and completion design for future appraisal wells. Moreover, the paper highlights some of the additional challenges that this strategy may evoke and shows how these challenges may be overcome in the future.

Uncertainties that applicable to oil & gas sector are different in scale. Hazardous and commercially very important global parameters and the priority by individuals have changed due to enhanced communication, transport facility, social detachment due to human relationships. The patriotic definitions have changed with Joint Ventures (JVs). Last century the spiritual quotient was high, and the "z" axis growth was very high. The working spirit for the cause was very high. Recently the "x" axis (material) growth has changed the social texture, "Why not me" to "why me"? The "y" axis growth with emotional quotient has played its role. High Emotional Quotient (EQ) people occupied higher positions. But to bind everybody and deliver requires High Spiritual Quotient (SQ). The uncertainties and social injustice can be superseded by evolving people. Our oil industry developed more on "x" axis rather on "y" axis. This resulted in reduction on "z" axis growth. Some point's worth to be noted are 1.World Drama: All the employees have to play some defined roles and excel. 2. Same level working: The senior reporting to junior by age/date of joining/date of position holding has also has changed. The previous logics do not hold good. 3. Parts of same chain: All the workers are equal parts of the chain. One least important link can cause the disaster/ zero output. This needs to be addressed. 4. Z axis growth: This helps you to work for the organization even if you (apparently) feel the fruits are taken by somebody else. 5. Writing your own arc: work for your own satisfaction. 6. Part of family/staying together and 7.Counseling and gap addressing and will be discussed in the paper.

Diffra West is a medium size oil field in Muglad basin of Sudan. Oil is accumulated in multiple sandstone reservoirs of AD and BE formations. The field has been developed through conventional vertical wells and electrical submersible pumps (ESP's) are in use to lift the oil. Initial well productivity was very good. Currently the field is facing the challenge of high water cut which is masking the oil production and will result in lower recovery factor than envisaged in field development plan (FDP). Arresting the production decline by controlling the excess water production is crucial for achieving the targeted recovery factor. Well intervention programmes have given mixed results in view of inadequate diagnosis of source of water based on swab tests. This paper discusses the use of Production Logging Tool (PLT) for identification of water source and implemention of corrective action in order to revive and improve the oil production of an up-dip well in the Diffra West field. The decision to use the tool was guided by prudent reservoir monitoring and analysis after misleading swabbing test that would have led to permanent isolation of the main producing formation in this well. The field was producing oil with water cut of about 60% when it was decided to investigate the source of the water. Performance of updip wells was also affected due to high water cut. D5 which is an up-dip well was selected for this study due to its better position and expected higher gain after workover job (WOJ) compared to other wells. A swabbing test was used as an initial attempt to identify the water source which indicated that the lower formation, zone-6, was producing 100% water. Obvious decision is to isolate it. However, a through performance analysis of the wells in the field revealed that downdip wells were producing oil from this formation. Most of these downdip wells have commingled production from zone#6 and other zones. Swab test of zone-6 confirmed oil. Two recently drilled wells completed in zone-6 are also producing significant amount of oil. Therefore, the swabbing result of zone-6 in well D5 appears unreliable and inconclusive. Sometimes these inconclusive results are observed due to limited number of swabs. The ambiguity of the swab test together with the good performance of other wells completed in zone-6 warranted the resolution of this issue using PLT which is not so easy in wells completed with ESP. PLT results confirmed that zone-6 is producing significant volume of oil. This is quite consistent with the overall field assessment. Further, the PLT results indicate that most of the oil produced by this well is actually from this formation and other sub-layers are contributing only 25 to 35 percent. Thus a prolific contributing layer has not been prematurely isolated in this well due to improper analysis and this translates into reaping around 500 BOPD for the company. This is the first time of running PLT in ESP well in this field and the encouraging result will be useful in the analysis of remaining wells of the field.

Heavy oil is an unconventional oil resource that is characterized by high viscosities and high densities compared to conventional oil. Most heavy oil reservoirs are deposit in shallow depths. Issaran oil field is located 290 KM southeast of Cairo and 3KM inland from the western shore of the Gulf of Suez covering 20,000 acres. The field was discovered on 1981. The Zeit Sand formation in Issaran is highly unconsolidated sandstone. The oil is 10-12 API. The top of reservoir depth is around 700-800 ft, the thickness is around 15 ft. The initial reservoir pressure and temperature are 250 psi and 90°F respectively. The oil viscosity is more than 4000 cp at standard conditions and the reservoir rock is oil wet with 5-10% H2S content. The highly unconsolidated nature of the sand and the thin pay (heat losses) makes the economical production of Zeit Sand very challenging. The OOIP in the developed area is estimates at around 2.5 MMSTB with estimated 35 % recovery factor using steam injection. The productivity of the wells initially before steaming is very low and the average cold production per well was below 5-10 BOPD. In 2009 Scimitar initiated a reservoir simulation to study the optimum development scenario in term of wells spacing and injection/production scheme. The model assumed there is no aquifer existing (as per G&G interpretation). As of Dec. 2009, it was decided to develop the area based on 150 mt spacing (18 new wells were drilled and 9 old wells have been re-completed in Zeit sand. This project faced a lot of challenge to produce Zeit sand formation either by cyclic steam stimulation or by steam flooding injection in the gas cap or oil leg wells, this paper will illustrate the different phases of this project and the challenges that were faced to complete the wells and handle the unconsolidated sand problem. Every effort was made to keep the cumulative voidage replacement ratio around one and the ultimate steam oil ratio below five which will have adequate reflect on the economics of the projects.

The oil and gas industry needs to plug the capability gap with pertinent technology that embraces the current trends to improving productivity. Digital oil fields have to engage the geosciences community and the business decision makers, surfacing knowledge from the plethora of accumulated data, both real-time and historical. Solutions must integrate not only the data, but extant applications and physical monitoring systems, and enable efficient collaboration between these facets to perform tasks faster and with more effectiveness and efficiency. With improved workflows and computing potential, it is now possible to ascertain the risk assessment and quantification of uncertainty inherent in improving productivity. The cost implied by poor predictions has to be mitigated by improved integration of disciplines and data fusion by adopting soft computing methods such as neural networks, fuzzy logic and probabilistic reasoning instilled into efficient workflows and processes. Reservoir characterization is a crucial player in modern reservoir management, and can lead to improved and timely reservoir decisions and this leads to heightened value of the oil and gas assets. This paper draws upon a case study that ameliorates the path to knowledge that is derived from available data. Let us look at a reservoir surveillance management solution that embraces a predictive detection and alerting solution to improve production forecasting and planning, and so assist in managing corporate risks and investments. Also, as we walk through a digital oil field workflow, we can focus on some of the soft computing techniques such as neural networks and fuzzy logic that lend credence in reservoir characterization.

Formation damage, a common problem associated with field operations, is often a major factor in reducing the productivity and injectivity of a well in a petroleum reservoir. Numerous laboratory and field studies indicate that formation damage occurs during many phases of reservoir development – drilling, completion, workover, production, stimulation, water flooding, or improved oil recovery. Formation damage is a process of initial permeability reduction. At present many mathematic formation damage models are developed. These models contain a number of parameters that is difficult to determine and mostly are not appropriate for field usage. We offered a way from lab to field scale that takes into account the process of formation damage during reservoir development. Analyzing the results of laboratory experiments and formation damage studies we defined that permeability has similar kinetics of alteration for different damaging mechanism. Next we determined the principal damaging mechanisms of real oil formation and associated them with laboratory relations of permeability alteration. As a result the integrated relations of permeability reduction and the new model of formation damage were obtained. This method was used as a predictive tool for quantitative predictions of field development showings for different rock types and operation strategies. Equations of permeability kinetics were integrated into reservoir simulator. The effect of permeability kinetics on formation development process was shown concerning clay oil formation. Based on laboratory and field observations the methods of enhanced oil recovery and formation damage prevention were proposed.

GDF-SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this basin, the main gas levels comprise the Cambrian and Upper-Ordovician reservoirs, sealed and sourced by the Silurian "Hot Shales" Formation. During the exploration and appraisal phases of the project, an intensive drilling program, including coring, standard logging and imaging (FMI), following a 3D seismic campaign was performed. Integrated study was done to investigate the suspected impact of natural fractures on the reservoir performances, to suggest potential geological drivers on fracture type (such as diffuse fractures and fracture swarms, if any) and on fracture distribution. The hydraulic properties of the fractures, based on available dynamic data were also evaluated. Indeed, accurate information on fault network and on fracture properties is essential to improve strategies for maximising hydrocarbon recovery, by optimising well location or directional drilling. Various seismic anisotropy "fracture relevant" attributes (RMS, Coherence and Dip) were selected and jointly used in a multi-variable statistical process called Seismic Facies Analysis (SFA). This gave a preliminary interpretation of the seismic facies in terms of fracture density that was completed and validated with well data and curvature analysis. The curvature pointed out various scale lineaments fully consistent with previous work. It concludes on predominance of fault-related fractures. According to dynamic data, well productivity may be enhanced by fracturation by a factor up to 12. The resulting fracture probability map was used to build a 3D fracture model with IFP and FracaFlow® software dedicated for fracture analysis and fracture modelling. For each well, a local discrete fracturation model was built. The length and intrinsic permeability of fractures were then calibrated using KH determined by well test interpretation and production log analysis. The final result consisted in computing the equivalent properties of the fracture network in each cell of the reservoir grid in order to perform the reservoir simulation. In this study, we present the results of production log (PLT) matched with success. The same fracture parameters were also used to match consistently the production log of the other wells. The integration of a wide type of data to analyse the natural fractures of this Algerian gas field leads to a fully consistent and well-constrained fracture model.

Restoring the well's productivity from existing damaged or partially damaged formations has been the objective of many operators over the years. The damaged or partially damged formations requires to diagnose the causes of the damage in order to design the proper stimulation treatment to remove the damage and restore the well productivity. Drilling fluid, completion fluid and kill fluid have the potential to be the most damaging portion of reservoir life.

Abstract The rapid post-fracture production rate decline observed in both oil and gas wells is normally associated with loss of fracture conductivity, often attributed to invasion of formation fines into the proppant pack, loss of fracture width caused by proppant flowback, and fines derived from proppant crushing. However, recent studies have indicated that solid material generated from a geochemical process in the fracture face known as proppant diagenesis has considerable impact on proppant conductivity. Although diagenesis is a slow geological process, lab tests show that proppant diagenesis can occur in fractions of a year. Post-fracture rapid production decline in high-temperature/high-stress wells seems to be the main symptom of proppant diagenesis. Recent lab tests have shown that the process can be prevented by isolating the direct contact proppant/ formation through the use of hydrophobic materials. The liquid resin systems (LRS), a specific type of hydrophobic material, have been used in the industry to prevent proppant flowback. The proppant is coated on-the-fly on location with a LRS. This technology has also proved to increase and sustain fracture conductivity over time. The production data presented in this paper comes from some tight-gas fields located at the Burgos Basin in north Mexico. The formation fractured is an intermediate/high-temperature and high-stress sandstone. The wells previously fractured in these fields historically had a rapid post-fracture production decline rate. The wells successfully treated with LRS material show a significant production increase compared to untreated offset wells because of a substantial change of the conductivity of the fracture. Based on laboratory experiments on proppant diagenesis and field results, it has been observed that the proppant diagenesis protection treatment provided by the LRS significantly contributed to the production increase of the treated wells. Introduction The production decline curve affected by reservoir conditions seems to be related to unknown downhole damage that, if treated properly, might resolve the problem and provide sustained productivity in mid- and long-term investments. This paper analyzes the results from three different gas fields located in the Burgos Basin in northeast Mexico. The wells used for the analysis were fractured using a patented resin-coating process to treat the proppant. The production results were compared with equivalent offset wells. Field results indicated that significant long-term well productivity is achieved when proper engineering practices are used to prevent harmful downhole chemical reactions, especially in reservoirs with severe stress and temperature conditions. Reservoir Geology In 1945, gas was discovered at the Burgos Basin located in northeastern Mexico. Today it is the largest nonassociated gas-producing basin of the four in Mexico. The basin is a structural and stratigraphic continuation of the geosinclinal in the Gulf of Mexico. The gas fields are located along the border between Mexico and the U.S. The stratigraphic column includes sediments from the Paleocene trend with a thickness up to 30,000 ft (Fig. 1). The producing trends include, from west to east, the Jurassic-Cretaceous, Paleocene-Eocene, Wilcox-Queen City, Jackson-Yegua, Oligocene Frio-Vicksburg, and Miocene trends (Fig. 2). The geological structure of the gas fields are complex and made up of numerous independent blocks with very low-permeability sandy reservoirs. The Burgos Basin produces from clastic Paleocene in the western portion of the basin to the Miocene in the east (Rivas et al. 2007).

Abstract At present, about half of Hassi Messaoud field output is being produced from hundreds of non-conventional wells. Two horizontal well (HW) applications are being used; new infill medium-radius horizontal wells in between productive zones and re-entry of dry-to-poor vertical producers all over the field using short-radius equipment. The purpose of both projects is to recover incremental oil from poor-quality reservoir parts in order to boost overall production and improve oil recovery. Horizontal well technology has proven to be a good alternative to overcome reservoir areal heterogeneity and intercept natural fractures when present in the reservoir. Although the two techniques have significantly improved production from marginal areas, several limitations and problems still have to be addressed. Challenges include weaker-than-expected productivities, rapid production decline rates in most wells, difficulties in data acquisition and inadequate completions for both remedial stimulation and zonal isolation. This study attempts to bridge production profiles with well and reservoir parameters such as; well length, permeability, vertical communication, lateral heterogeneity and anisotropy, near wellbore damage, pressure support,…etc. The article presents a comprehensive analysis of horizontal wells in the field and investigates many aspects of the observed success and failure cases. It also discusses the benefits of underbalanced drilling and pre-perforated liner completions. By benchmarking current well performances, the paper draws some suggestions for well design and completion strategies for prospective wells. Introduction The Hassi Messaoud reservoir has been on stream since 1958. Currently, it produces about 65 Mm3/D of 45°API oil from a thick Cambro-Ordovician sandstone formation. The structure is a flattened anticline with a sequence of horts and grabbens contained by faults in a submeridian direction. The faults are generally oriented SSW to NNE and cross the entire reservoir. The depositional environment is fluvial at the bottom to marine at the top. The shaly sandstone contains silt interbeds which have a thickness between 0.2 and 0.4 m with a metric to kilometric lateral extension. The reservoir is naturally fractured in some parts because of tectonic activity. Fractures are either open or plugged with materials such as shale, silica, anhydrite, pyrite, and bitumen. The reservoir is subdivided into four distinct formations—Ri, Ra, R2, and R3—in addition to a zone of alternance with Ra-Ri and R2 being the main and secondary reservoirs respectively. The producing Ra-Ri is subdivided into six intervals: D5, D4, D3, D2, ID, and D1. The reservoir has a porosity ranging from 6 to 12 %. Overall, the permeability is low with a range from less than 1 to more than 100 md in open-fissures layers. The reservoir was initially undersaturated with an oil saturation of about 80%. The reservoir was subdivided into productive zones. Most zones are under miscible gas flooding. Five zones are under water injection. Up until 1995, the reservoir was developed using vertical wells. Along with matrix treatments, hydraulic fracturing is extensively used with more than 300 wells already treated to compensate for low permeability or to bypass nearby wellbore damage. Gaslift is used for production activation throughout the field. Pilot projects for horizontal well technology started in the mid 1990s. The objective was to develop the reservoir's areas where conventional vertical drilling deemed unsuccessful. The first application was drilling medium-radius infill wells in lower permeability areas and at the peripheries of zones where heterogeneities are high and reservoir continuity is uncertain. The second technique consisted of re-entering dry-to-poor vertical wells using short radius drilling equipment. In this study we discuss the implementation, lessons learned and challenges of these unconventional wells. Many reservoir and production aspects are also discussed throughout the paper.