Abstract A new analytical model for optimizing hydraulic fracture conductivity has been proposed by modifying the model developed by a researcher using the formula obtained from classical 2D Perkins-Kern-Nordgren (PKN) model as a function of proppant viscosity and the young modulus (rock compaction). This study shows that fracture conductivity depends on penetration ratio and fracture conductivity decreases as penetration ratio increases and this is due to the increase in overburden pressure of the rock and viscosity of the proppant fluid and this lead to reduction in productivity. It was proposed that productivity can be increased by increasing the fracture pressure and the viscosity of the fluid depending on the type of formation.

Abstract Reliable gas well tests provide valuable data for production optimization and maximizing ultimate recovery of gas reserves. Poor data quality, heightened process safety risks and elevated OPEX are inherent limitations in the methods undertaken by operators to measure Condensate Gas Ratio (CGR) during Multi-Rate Tests (MRT) and routine production. This paper describes the steps undertaken by the team in BERA to overcome this challenge by utilizing the density-measuring capability of the Coriolis meter. A density-based algorithm was setup using a designed decantation procedure and encoded in the control system for real-time measurements and made available in the office domain. This technique provides improved data quality, ease of well surveillance and a long-term cost avoiding option while simultaneously increasing the flexibility and ease of executing MRTs. It eliminates the need for manual sampling with its associated process safety concerns.

The XK field is a mature offshore asset with post peak production characterized by rapid oil decline rate and steep water cut. Many wells have ceased flow prematurely over time and non-rig interventions to reactivate and restore the wells to production had typically been ineffective owing to consistent low tubing head pressures and well construction/completions. Furthermore, the plan to initiate gaslift operations in the field was challenged by the lack of gaslift separator, compressor unit and gas line coupled with the fact that many of the wells were completed without gaslift mandrels. The deployment of innovative inter well gaslift, utilizing Gas Liquid Cylindrical Cyclone (GLCC) separator saved the situation and enabled achievement of the gaslift objective. The result was the successful restoration of three (3) long shut-in wells and associated increased oil production in the field. This paper discusses the opportunities and challenges from inter well gaslift initiation and operations in XK field and the enormous potential as a low cost and efficient system for rejuvenating Brown Fields.

In challenging horizontal wellbores with subhydrostatic well conditions and the inherent uncertainties associated with mechanical bridge plug installation, the balanced cement plug concept becomes the appropriate method for cement packer installation. The balanced cement plug method requires creating a balanced U-tube with the hydrostatic pressure consisting of a column of brine, spacers, and cement slurry in the annulus of a tubing/drillstring equating the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated, accounting for fluids both inside and outside the pipe at the given gradient/head, resulting in a hydrostatically "balanced system." Recently, this technology has been successfully deployed for cement packer design and installation using coiled tubing (CT) to place 813 ft of cement packer in the 3 1/2-in. tubing × 9 5/8-in.casing annulus from bottom of tubing punch at 5,913 to 5,100 ft MD (685 ft above shallowest perforations). The location of the production packer at a depth of 629 ft with 9.6-lbm/gal calcium chloride brine (cement accelerator) existing below the tubing punch interval in the tubing-casing annulus presents challenges with respect to the cement slumping through the brine. Detailed engineering design and execution is necessary to overcoming such inherent challenges. The zonal isolation of the existing subhydrostatic mature oil zone within the horizontal wellbore (793 ft blank liner and 1,698 ft predrilled liner) was achieved through placement of 575 ft of cement plug in the 3 1/2-in. tubing from 6,511 to 5936 ft MD. A rigless through-tubing balanced cement plug concept for cement packer installation and reperforations was deployed to access behind pipe oil reserves in a high-angle (69 to 72º) deviated well, Offshore Niger Delta. Design considerations were reviewed and precautions for placement through CT were discussed. The operation was successfully executed and the temperature log confirmed the TOC as proposed during the design phase. The HUD in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow tests have proven the success of the design and procedure implemented in challenging wellbores. The stable production post-hookup to the production line presents 212% incremental production without sand exclusion against the proposed well intervention objectives. This presents the advancement in cement packer installation in complex well trajectory with high potential of U-tubing attributed to failed retainer packer for accessing bypassed oil reserves. The balanced cement plug engineering design presents an interplay between 8.5-lbm/gal inhibited sea water, 8.33-lbm/gal spacer (drill water+surfactant), 8.5- and 9.7-lbm/gal brine, 15.8-lbm/gal neat cement slurry above the 9.6-lbm/gal existing completion calcium chloride brine, and pressures in the casing/tubing annulus and tubing to balance the fluid without a retainer packer.

The unique introduction of production screens with mechanically shiftable flow isolation sleeves and inflow control devices for better injection flow distribution (ICD) fit with innovative dissolvable metal plugging rods that allow wash pipe free horizontal completion installation on a deep offshore project in Nigeria. This unique application provides the function of a mechanical selective completion with the incorporation of an ICD solution tailored to the reservoir with wash pipe-free execution. This would allow for selective injection from one zone to a comingled injection activated using mechanical intervention means while maintaining full compatibility with the already designed upper completion and the existing wellhead and topside equipment, as is. The completion was successfully installed following the standard field operations practices used on previous completions within the same field. The Egina development plan, operating with a standardized and simple design, does not provide for an intelligent completion that allows remotely activated zonal selectivity. Two separate reservoir zones, with two panels each, were targeted for water injection to achieve the sweep of by-passed oil in the shallower panels connected to two producer wells and pressure mainteneance in the deeper panels connected to one producer well. Commingled injection from start would result in early water breakthrough on one of the two producer wells connected to the shallower reservoir panels by virtue of both well drains being almost at same level depthwise, TVD/MSL. A solution was selected that would combine the two target reservoir zones on a single well. This would allow for selective injection using screens with mechanically shiftable integral sliding sleeves, maintaining temporary access or isolation on the shallower interval. This solution would allow for drilling one single water injection well instead of two. Incorporating ICDs in the deeper reservoir panels with " a dissolvable plug solution " allowed for a better injection flow distribution as well as the completion deployment, wash pipe free. Fluid compatibility testing was performed with dissolvable metals to establish dissolution rates under existing reservoir conditions with mud, brine, and filter cake breaker at field standard formulations. This provides an additional option for running wash pipe free when running lower completions in deepwater wells offshore West Africa. Drilling one well instead of two and deploying completions wash pipe free, allowed for CAPEX savings in the region of $60 Million. No modification to the existing completion processes was necessary with respect to the procedure for deploying completions, washing down or subsequently placing a filtercake breaker treatment. This paper describes the rationale behind the well design philosophy and the operational procedures that introduced a global first deployment of injection screens with mechanically shiftable integral sliding sleeves and ICDs with dissolvable plugs in deep water openhole horizontal completion. The successful installation, completion equipment functionality, and well injectivity test results are discussed.

Subsurface uncertainties in reservoir characterization remains a challenge in decision making in the development phase of hydrocarbon maturation process due to geological complexity and limitations in reservoir data to provide sufficient understanding of the subsurface. This study focuses on identifying, managing, narrowing these uncertainties and generating reservoir realizations and optimum development concept consistent with available data. Hence, the objective of this study is to generate a technically feasible & economically viable development plan for X1, X2W and X2E reservoirs in KOCA field. The methodology deployed on this study is a multi-disciplinary integrated approach in a parallel setting with early focus on uncertainty identification, quantification, management and iterations amongst the team. Sensitivity analysis was used to evaluate the respective impact of the identified uncertainties on in-place and recoverable volumes and realizations were constrained by the most impacting uncertain parameters to generate a low case, base case and high case valid realizations of the subsurface. Development concepts were selected to optimize recovery using the base case realization with preliminary economic evaluations used to determine concepts economic viability. The result of this study identifies Structure, Net-to-Gross, and Permeability as the top three uncertainties with most impact on volumes. Deterministic low, base and high case GIIP volumes computed are 354Bscf, 681Bscf and 1.1Tscf, while recoveries were 261Bscf, 546Bscf and 913Bscf respectively. Deterministic low, base and high case STOIIP volumes computed are 0.4MMSTB, 1.5MMSTB and 3.4MMSTB, while recoveries were 0.1MMSTB, 0.2MMSTB, and 0.02MMSTB respectively. Optimum subsurface development concept is two vertical gas well, no horizontal well is needed to develop the thin (12ft) oil rim and finally quick look project economics revealed that the project would be economically viable even for the Low-Case outcome: NPV (10%) is $150M and VIR (10%) is 3.92.

A major cause of increase in the number of well abandonments in small heterogenous formations with high geological complexities is early water breakthrough into completions which leaves pockets of bypassed oil that ultimately affects the overall recovery from such formations. This paper highlights some reservoir management strategies adopted to improve reserves from a Niger Delta formation with an API of 22 Deg. Reservoir management strategies adopted included the use of down hole gauges, inflow control devices, and detailed production/injection surveillance. Updated 3D simulation model and material balance analysis were also used for evaluation of waterflood recovery efficiency and real time Reservoir management decisions. Other Reservoir management practice helped in stimulating gas cap expansion that increased daily oil rate from this reservoir and field gas rate that helped in gas lifting wells in other heavy oil reservoirs with high BSW.

Inflow control devices (ICD) have been used to balance flux around completions and also delay break-through of unwanted water into completions. Inflow-control devices (ICDs) were provided to curtail water production from heterogenous reservoirs with strong aquifer systems and/or supported with water injection. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system. This additional pressure drop does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells. Pressure losses from horizontal wellbores which do not contribute to increased production is seen as skin and consequently, a new equation was derived to estimate skin due to ICD in horizontal completions. In this paper, a horizontal well equipped with inflow control device which was drilled in one of the off-shore fields of the Niger Delta region was used as a case study in evaluating the performance of an ICD completion. The new equation was used to estimate the skin due to ICD of this completion and the result obtained is compared with the skin obtained using pressure transient analysis and the results obtained from both approach are similar. This paper shares how the new equation was used to estimate skin due to ICD and the result comparison with that of a pressure transient analysis.

When a reservoir is bounded, well productivity is affected in the long time according to the nature of the boundary. The length of time for oil production is strongly affected by well location with respect to the boundary, whether the boundaries are single, paired and vertical or paired and inclined. It therefore becomes important that well location is guided to achieve prolong oil production. The guide may be achieved from solution to a specific flow equation describing pressure distribution. The solution prescribes rates and well location for available reservoir system properties. In this paper, dimensionless pressure derivatives of a vertical oil well are studied to search for optium well location that can guarantee satisfactory oil production without premature influence of the external boundaries. The external boundaries are sealing and are considered to be inclined. The solution to this dimensionless diffusivity equation is utilized. The derivatives are computed from the total dimensionless pressure expression summing all the image wells by superposition principle. The Python and Excel softwares were deployed to compute all the dimensionless pressures for the different well designs. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the sealing faults. The optimum well location from the sealing faults is inversely proportional to the inclined angles. This implies that nearer wells to faults produce optimally at a given time of production. Furthermore, the relationship between well distance and productivity has no maximum or minimum points. Therefore there is no particular optimum location distance from the faults for optimum productivity. Optimum well location for sealing boundaries depends on many factors, such as production profile, well design, faults angle, fluid type and lease size. Furthermore, it was also observed that the wellbore radius has no significant effect on the dimensionless pressure derivative, optimum well location and the optimum time of production.

Production performance of well assets changes as oil and gas assets mature leading to increased breakthrough of associated fluids (gas and/or water). Classic single-phase Pressure Transient Analysis (PTA) becomes limited with multiphase flow due to the underlying principles governing single phase flow resulting in errorneous interpretation results. This paper presents the outcome of PTA interpetaion results for oil production wells that recently experienced water breakthrough to assess the value of performing post-breakthrough multiphase pressure transient analysis. Using field data, the results obtained from single-phase pressure transient analyses on buildups after breakthrough were inconsistent with results obtained prior to breakthrough. Multiphase pressure transient analyses were performed on the same post-breakthrough buildup data and the results were compared with the historical well and reservoir behaviors when the well was still in single phase and single-phase pressure transient was conducted. The results indicated excellent agreement in terms of well and reservoir properties between the buildups obtained during two-phase flow and those obtained during single phase flow when multiphase pressure transient analyses were performed on the buildups during two-phase flow. The study also compared two multiphase pressure transient analysis methodologies: Perrine (1956 ) and Kamal-Pan (2010) . Using field data, the results obtained from these two methodologies were observed to be consistent. A key lesson learned during this study was the importance of the relative permeability data on the results of multiphase pressure transient analysis.

The diffusivity equation for a real gas flow through porous media is nonlinear due to the variations of fluid properties with pressure. Consequently, several approaches have been presented in the literature to account for these variations. Unfortunately, while some of these approaches are heavily based on iterative schemes, others are based on functional relations of fluid properties and pressure. In this paper, we present a new set of rate-decline type curves to analyze and predict gas well performance. The rate-decline type curves have been developed based on a semi-analytical model. The variations of gas properties have been accounted for in a drawdown parameter. Results based on numerical and field data show that the proposed gas well rate-decline type curves provide at least two advantages over the existing methods: First, the gas properties are relatively easily handled via the drawdown parameter; and, second, the original gas-in-place is determined without a time-consuming iterative scheme or functional relations of fluid properties with pressure.

The Tertiary Niger Delta Basin is dominated by a friable, loosely consolidated sandstone formations indicating the likelihood of sand production ocuuring during hydrocarbon production in such formations. The aim of this study was to develop a simple mechanistic model for predicting sand production rate (SPR) in Niger-Delta wells. Two basic criteria (static sanding criteria and the dynamic requirement for fluidization of the produced sand) were used in developing this model. A generic mechanistic model that incorporates the concept of dimensionless quantities associated with sand prediction was developed. In developing the model, loading factor, Reynolds Number, water cut and gas-liquid ratio, GLR were considered. A dimensionless sand production rate (SPR) correlation index was the output from the proposed model. Results indicated that every reservoir has a unique SPR correlation index which represents its propensity to produce sand or its sanding identity. Validation of the proposed model was conducted by comparing the model prediction results with field data. Model validation results showed an agreement between predicted with field results with an acceptable maximum deviation of less than 5% in for onshore wells. The proposed model was further compared to existing models and prediction results show that the proposed model gave better results than others especially when the boost factor, GLR is significantly high. The applications of this study range from field development plans and economics to reservoir management, down to general well completion design and strategies.

A new analytical model for optimizing hydraulic fracture conductivity has been proposed by modifying the model developed by a researcher using the formula obtained from classical 2D Perkins-Kern-Nordgren (PKN) model as a function of proppant viscosity and the young modulus (rock compaction). This study shows that fracture conductivity depends on penetration ratio and fracture conductivity decreases as penetration ratio increases and this is due to the increase in overburden pressure of the rock and viscosity of the proppant fluid and this lead to reduction in productivity. It was proposed that productivity can be increased by increasing the fracture pressure and the viscosity of the fluid depending on the type of formation.

Agbami Field is a deepwater producing asset off the coast of the Niger Delta region in Nigeria. The production system comprises of 26 subsea production wells, 8 subsea production manifolds, subsea flowlines and subsea risers respectively. The production wells are intelligent completions made up of 22 dual zone well completions and 8 single zone well completions. Dual zone well completions are equipped with Interval Control Valves (ICVs) for zonal control & isolation. They are also equipped with several pressure/temperature (P/T) gauges from the sand-face completion to topsides for real time measurement. Production commenced in 2008 and peak production was achieved a year later in 2009. Field production remained at peak for about 8 years. The stellar field performances have been achieved through several reservoir management best practices. These include, but not limited to, robust initial field development strategy, infill development, acid stimulation operations, Real Time Reservoir Management (RTRM) and production optimization using Intelligent Well Completion (IWC). This paper demonstrates the development of an automated system which performs Production Network Model calibration and assessment of production optimization opportunities. The key considerations for automated calibration and optimization system workflow development will be presented. Since deployment, the automated calibration and optimization system has reduced the manhours spent with manual model calibration and optimization assessment by 85%. Lessons learned during the development and deployment of the automated system as well as production gains realized from the solution will be highlighted.

This paper evaluates the profitability of developing a Nigerian marginal oil field in a low oil price environment. The undeveloped asset is located offshore, and remains undeveloped due to field size and remote location. Recent seismic interpretation suggested that the field could be larger than previous estimates, and this triggered re-evaluation for development. Subsurface and economic assessments were completed to evaluate the profitability of developing the field, and the NPV, profit to investment ratio, DCFR, payback period, and breakeven oil price indicators are presented. The base case development scenario was unattractive, and additional sensitivities were completed to transform the marginal field into an attractive investment. The paper presents standard working practices used to evaluate the profitability of petroleum upstream assets. It also shows why economics is the bottom line of petroleum assets, recommends guidelines for selecting upstream investment projects and participating in petroleum licensing bid rounds, and illustrates how hydraulic fracturing has transformed low permeability oil fields in the USA into economic projects.

The changing landscape of global energy and fluctuations in commodity prices have driven companies to get more efficient means to sustain their businesses. With companies seeking more from their assets via rigless interventions, the trend has been that the low-hanging opportunities have been executed. The opportunities left are either too complex for rigless interventions or the expected production is too small to make major-rig workovers economic. We discuss such complex opportunities that were revisited to ensure sustained production from mature fields. The first case study discusses a gas-lift opportunity that was suspended when tubing leaks were discovered. The three holes posed a challenge since they were quite shallow and not suitable to be used as the injection-point of the gas. The work-around was to use a tubing patch to cover the holes without significantly reducing tubing ID as much as a pack-off would to allow for future well re-entry. The second case study discusses a well with a tubing restriction that prevented perforation addition. The job stalled when a gauge cutter (similar OD as the available gun) barely passed through the restriction during a dummy run. Even if the gun passed through and was detonated, the expended gun would be swollen and irretrievable due to the restriction. A modified perforating gun that disintegrated upon detonation was used, eliminating the need to retrieve the expended gun. The third case study was a well completed with mud five decades ago. The mud had caked; preventing any chance of executing a poor boy gas lift. The solution was to adapt the cement-bond-log technique to identify regions of moveable mud in the annulus with the mud subsequently displaced out by pumping. The lesson learned is that opportunities that have stalled due to their complexity can still be executed via rigless workovers by leveraging on existing technologies with slight adaptations to create well-specific solutions.

The objective of this paper is to share lessons from an intensive study of a mature reservoir and highlight its results. This study also aims to demonstrate the value that can be obtained from a mature conventional oil reservoir when the appropriate assessment processes are utilized. The case study is an offshore oil reservoir with over 50 years of production with waterflooding for almost a decade. The dynamic simulation model from an earlier assessment of the reservoir showed significant deviation following years of waterflooding, as it became more challenging to understand the water front movement, predict water cut changes and deliver more reliable liquid production forecasts. The reservoir had historical challenges with water production and matching the water-cut from producing wells emphasizing the deviation of the existing simulation model from actual data. As a result, a cold-eye review of all available data without anchoring on prior interpretations was required. An updated reservoir characterization and earth modelling methodology was applied during the study with attendant improvements in structural and stratigraphic representation of the reservoir. A full-field assessment methodology was employed in the study both for the fault framework and model building, ensuring the inter-reservoir connections and dependencies were captured. Additional scrutiny was applied to initial fluid contacts, leading to the resolution of longstanding uncertainties. This resulted in the delivery of a new dynamic simulation model with a much better water cut history match compared to the previous study. Fluid contact tracking over time was also better matched using the new model. The new model indicated an increase in original oil in place of 38% leading to the identification of 2 new infill producer opportunities with total estimated ultimate recovery of several millions of oil barrels.

Reliable gas well tests provide valuable data for production optimization and maximizing ultimate recovery of gas reserves. Poor data quality, heightened process safety risks and elevated OPEX are inherent limitations in the methods undertaken by operators to measure Condensate Gas Ratio (CGR) during Multi-Rate Tests (MRT) and routine production. This paper describes the steps undertaken by the team in BERA to overcome this challenge by utilizing the density-measuring capability of the Coriolis meter. A density-based algorithm was setup using a designed decantation procedure and encoded in the control system for real-time measurements and made available in the office domain. This technique provides improved data quality, ease of well surveillance and a long-term cost avoiding option while simultaneously increasing the flexibility and ease of executing MRTs. It eliminates the need for manual sampling with its associated process safety concerns.

Casing design plays an important role in the successful drilling of a well and accounts for a substantial percentage of well costs. The goal of casing design is to get an optimal design that will withstand stress and other factors that affect casing throughout the lifetime of the well. The conventional approach to casing design uses a deterministic working stress design (WSD), where minimum strength requirements of the casing are determined by comparing casing strength to the magnitude of severe accidental loads that may occur during the lifetime of the well. Uncertainties in the load and strength of the casing are accounted for by multipliers called safety factors (SFs) that are mostly based on experience and do not reflect the probability or consequence of the different casing failure modes. This approach may result in overly conservative casing designs, or design requirements for severe conditions that are expensive, leading to higher well costs. In this paper, the Monte Carlo Simulation (MCS) method is applied to casing design, where uncertainties in casing loads are considered explicitly by assigning probability distributions to safety factors that affect design loads. As the MCS method predicts the casing safety factor probability, it gives a better view of the real uncertainties involved in the design. Acceptable probabilities of casing design load can be selected based on the cost and operating conditions the casing will undergo; thus, a probability approach to casing design is more flexible as it allows an explicit uncertainty-consistent designs compared to traditional working stress designs.

In conventional draw test analysis, initial reservoir pressure has to be known with precision to aid primarily to determine near wellbore skin. Furthermore, in old wells, the initial reservoir pressure has to be attained before drawdown. For very old wells and tight reservoirs therefore it would take painfuly long shutin time to eventually attain the initial reservoir pressure before drawdown. In largely depleted reservoirs, it may be impossible to actually attain the desired initial reservoir pressure even after a long shutin! Efforts at obtaining the initial reservoir pressure in all these cases would only yield the remaining reservoir pressure since fluid had been produced from the reservoir. On a semilog plot of flowing wellbore pressures versus time, it is not possible to estimate the reservoir pressure to even validate the recorded pressure before shutin. In this paper, a procedure has been developed to overcome these challenges. The new method plots flowing wellbore pressures against dimensionless pressures on linear axes, assuming infinte-acting flow. The plot gives a straight line with intercept on the flowing wellbore pressure axis yielding the remaining reservoir pressure on extrapolation to dinensionless pressure of zero. Although, developed for horizontal well flow, it can be adapted for vertical well flow with minimal effort. Mathematical procedure employed is based on selection of relevant source and Green’s functions for a horizontal well during infinite-acting flow and assuming the well purely as a line source. A case pressure drawdown test selected for analysis using the method developed here yielded very close reservoir pressure compared to the reservoir being characterized.